DEPARTMENT OF NATURAL RESOURCES Oil and Gas Conservation Commission PRACTICE AND PROCEDURE 2 CCR 404-1 [Editor’s Notes follow the text of the rules at the end of this CCR Document.] 100-SERIES DEFINITIONS ACT shall mean the Oil and Gas Conservation Act of the State of Colorado. 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.

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. 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, 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 minimize 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 regulated by the Colorado Department of Public Health and Environment, that (1) is either used exclusively by one owner or operator or used by more than one operator under an operating agreement; and (2) is operated for a period greater than three (3) years; and (3) receives for collection, treatment, temporary storage, and/or disposal produced water, drilling fluids, 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 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 resources, 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 operations; (d) develop agreed-upon measures to avoid, minimize, and mitigate the identified potential impacts; and (e) include other relevant information. 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 PITS used to contain fluids and solids produced during initial completion procedures, and not originally constructed for use in drilling operations. FLOWBACK PITS used to contain fluids and solids produced during initial completion procedures.

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).

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 that are exempt from regulation under Subtitle C of the Resource Conservation and Recovery Act (RCRA), 42 USC Sections 6921, et seq. 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: in 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, 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, 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.

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.

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, off- site habitat mitigation, or mitigation banking.

MULTI-WELL PITS shall mean pits used for treatment, storage, recycling, reuse, 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. 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. 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. 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 constitute: 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 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.

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 concentration 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 who protests the granting of the relief sought in the application as provided in Rule 509. RESPONSIBLE PARTY shall mean an owner or operator who conducts an oil and gas operation in a manner which is in contravention of any then-applicable provision of the Act, 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, and copies of the maps shall be attached as Appendix VII. 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. SENSITIVE AREA is an area vulnerable to potential significant adverse groundwater impacts, due to factors such as the presence of shallow groundwater or pathways for communication with deeper 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. 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, and copies of the maps shall be attached as Appendix VIII. The extent of sensitive wildlife habitat is subject to update on a periodic but no more frequent than 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.

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: (a) 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 constitute: BLOWDOWN PITS used to collect material resulting from, including but not limited to, the emptying or depressurizing of wells, vessels, or gas gathering systems. FLARE PITS used exclusively for flaring gas.

EMERGENCY PITS used to contain liquids 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.

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.

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 at the time of the termination of a construction stormwater permit issued by the Colorado Department of Public Health and Environment. 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.

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 non- Indians 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.

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 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 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, 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, 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. 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 at the operator’s local field office. 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, 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 Director or his or her designee. The Director 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 Director 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 Director, 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 Director.

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 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 operators, 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 or a health professional, the operator is responsible for providing the required information.

i. In the event the 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 or a health professional, the 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 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 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 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 by September 1, 2009 be labeled or posted with the following information:

1. A. Name of operator;
2. B. Operator’s emergency contact telephone number;
3. C. Tank capacity;
4. 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.

e. 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 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 601-608.

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 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 (15°)

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.

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;

(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);

(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 reasonably 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 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 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 hearing 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.

(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:

1. A. Included as 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.
2. B. Included as 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 as described in Rule 216.f.(3) above 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.

(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, PRODUCTION 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 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. 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 submitting a new Designation of Agent, Form 1A. All changes 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.

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 re- entry 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) Operational conflicts. The Permit-to-Drill shall be binding with respect to any operationally conflicting local governmental permit or land use approval process.

(3) 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

1. 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 8½" 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 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.

d. FORM 2A, OIL AND GAS LOCATION ASSESSMENT.

(1) 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.

(2) Exemptions. A new Form 2A shall not be required for the following:

1. 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;
2. 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;
3. C. Gathering lines;
4. D. Seismic operations;
5. E. Pipelines for oil, gas, or water; or F. Roads.

(3) Information requirements. In all instances, the Form 2A requires the attachment of the following information. Where the information required under this section has been 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.

1. A. A minimum of four (4) color photographs, one (1) of the staked location from each cardinal direction. Each photograph shall be identified by: date taken, well or location name, and direction of view.
2. 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.
3. 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.
4. 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.
5. 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.
6. F. Designation of the current land use(s) and landowner’s designated final land use(s) and basis for setting reclamation standards.
   1. 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.
   2. 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:
      1. aa. A topographic map showing the location of the site, and the location of the reference area; and 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.
7. G. Natural Resources Conservation Service (NRCS) soil map unit description.
8. 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:
   1. i. Construction layout drawing (construction and operation); and ii. Location cross-section plot (construction and operation).
9. 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.
10. 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.
11. K. Where the proposed oil and gas location is covered by a Comprehensive Drilling Plan accepted pursuant to Rule 216, a list of any conditions of approval.
12. 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.
13. M. Designation of whether the proposed oil and gas location is within sensitive wildlife habitat or a restricted surface occupancy area.
14. 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.
15. 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.

1. 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:
   1. 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:
      1. aa. Garfield;
      2. bb. Mesa;
      3. cc. Gunnison; or dd. Rio Blanco.
   2. 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;
   3. 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:
      1. aa. Is a production facility;
      2. bb. Is servicing multiple wells; and cc. Would not require any other Commission permit or facility registration.
2. 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.

1. 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.

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.

f. Oil and gas locations 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, the operator shall so indicate on the Oil and Gas Location Assessment, Form 2A.

g. 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.

h. Incomplete applications . Applications for Permit-to-Drill, Form 2, or Oil and Gas Location Assessments, Form 2A, which are submitted without the required information and 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 ten (10) days of 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 contacted to correct or provide requested information , otherwise the 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 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.

j. 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 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.

k. 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.

l. 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, 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) and 306. The Director shall report permits granted in such manner to the Commission at regularly scheduled monthly hearings.

m. Special circumstances for withholding approval of Application 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 a material threat to wildlife resources. Any such withholding of approval shall be limited to the 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 Rule 503.b.(7).

(2) 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.m., an operator may ask the Commission to issue an emergency order rescinding the Director's decision.

n. 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.l.(1) or (2), an operator may ask the Commission to issue an emergency order rescinding the Director's decision.

o. 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.

p. 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 Safety. 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.l.(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. 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:

1. A. The date on which the Form 2A was posted;
2. B. The date by which public comments must be received to be considered;
3. C. The address(es) to which the public may direct comments; and 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 accepted or 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.

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.

1. 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).
2. 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 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 two- feet, 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.

The operator shall consult in good faith, as provided below.

a. Consultation 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 good faith with the surface owner, or the surface owner’s appointed agent as provided for in Rule 305. Such consultation 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.

(1) Information provided by operator . When consulting with the surface owner or appointed agent, 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 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.

b. Consultation with local government.

(1) Local governments that have appointed a local governmental designee and have indicated to the Director a desire for 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.

1. 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:
   1. i. Consultation is required pursuant to a provision in the 1200-Series of these rules;
   2. 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.
2. 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
   1. (40) acres, or the Commission develops a basin-wide order involving wildlife or wildlife-related environmental concerns or protections.
3. 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.

1. A. The operator shall provide:
   1. i. A description of the oil and gas operation to be considered, including location;
   2. 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.
2. B. The Commission shall take into account the information submitted by the operator consistent with Rule 1202.c.
3. 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.

1. 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.
2. 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.
3. 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.
4. 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.
5. 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.

1. A. The Commission shall consult with the Colorado Department of Public Health and Environment on an Oil and Gas Location Assessment, Form 2A, where:
   1. 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;
   2. 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 rules intended for the protection of public health, safety, welfare, or the environment:
      1. aa. Rule 317B. Public Water System Protection;
      2. bb. Rule 325. Underground Disposal of Water;
      3. cc. Rule 603. Drilling and Well Servicing Operations and High Density Area Rules;
      4. dd. Rule 608. Coalbed Methane Wells;
      5. ee. Rule 805. Odors and Dust.
      6. 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.

2. 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.
3. 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.

1. 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.
2. 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.
3. C. Where consultation occurs pursuant to Rule 306.d.(1).A, it may include:
   1. i. Review of the permit application;
   2. ii. Discussions with the local governmental designee to better understand local government’s concerns;
   3. iii. Discussions with the Commission, operator, surface owner, or those potentially affected; and iv. Review of public comments.
4. 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:
   1. 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.
5. E. Where consultation occurs pursuant to Rule 306.d.(1).B, the Colorado Department of Public Health and Environment shall have the opportunity to:
   1. 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.

1. 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.
2. 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-to-Drill, Form 2, where applicable.
3. 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.
4. 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 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.

e. 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 agent) the opportunity to provide comments concerning preference for timing of such operations and all 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 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 for such purposes. Nothing shall prevent the surface owner from including a tenant in any consultation, whether or not appointed as the surface owner’s agent.

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 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. 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.

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 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 of 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.

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 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 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.

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. These logs 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 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 case- by-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

1. (50) feet below the depth of the base of the aquifer from which said deepest water well is 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 x- bentonite 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

1. 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.

(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, attached as part of Appendix VI, or by entering information 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.

(1) The Commission shall grant a variance if the operator demonstrates that:

1. 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:
   1. 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 mineral 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:

1. A. pH;
2. B. Alkalinity;
3. C. Specific conductance;
4. D. Major cations/anions (chloride, fluoride, sulfate, sodium);
5. E. Total dissolved solids;
6. F. BTEX/GRO/DRO;
7. G. TPH;
8. 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

1. (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:

1. A. pH;
2. B. Alkalinity;
3. C. Specific conductance;
4. D. Major cations/anions (chloride, fluoride, sulfate, sodium);
5. E. Total dissolved solids;
6. F. BTEX/GRO/DRO;
7. G. TPH;
8. 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

1. (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:

1. 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:
   1. i. pH;
   2. ii. Alkalinity;
   3. iii. Specific conductance;
   4. iv. Major cations/anions (chloride, fluoride, sulfate, sodium);
   5. v. Total dissolved solids;
   6. vi. BTEX/GRO/DRO;
   7. 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.

1. 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).
2. 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 the later of May 1, 2009 for federal land or on or after April 1, 2009 for all other land or the date Rule 317B became applicable to the oil and gas location 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:

1. 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:

1. 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.
2. 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.
3. C. For Internal Buffer Zones:
   1. i. Pitless drilling systems;
   2. ii. Flowback and stimulation fluids contained within tanks and placed on a well pad or in an area with downgradient perimeter berming;
   3. 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 2,500 feet or greater in depth. A well to be drilled two thousand five hundred (2,500) feet or greater 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 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

1. 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 or 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.

1. 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.
2. 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.
3. 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: E½; Township 2 North, Ranges 64 West through 68 West; Township 2 North, Range 69 West: E½; 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.

(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.

1. 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.
2. 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:

1. 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.
2. 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.
3. 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 one- half (½) mile of the proposed GWA infill well shall be selected.
4. D. If there are no water quality testing wells that meet the foregoing criteria, then initial baseline testing shall not be required.
5. 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.
6. 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 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.
7. 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:

1. 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.
2. 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.

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.

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:

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 Township 2 North Range 46 West: All Range 47 West: All Range 48 West: All Township 3 North Range 45 West: Sections 1 through 18 Range 46 West: All Range 47 West: All Range 48 West: All Township 4 North Range 45 West: All Range 46 West: All Range 47 West: All Range 48 West: All Township 5 North Range 45 West: All Range 46 West: All Range 47 West: All Range 48 West: All Township 6 North Range 45 West: All Range 46 West: All Range 47 West: All Range 48 West: All Township 7 North Range 45 West: All Range 46 West: All Range 47 West: All Township 8 North Range 45 West: All Range 46 West: All Range 47 West: All Township 9 North Range 45 West: Sections 19 through 36 Range 46 West: Sections 19 through 36 Range 47 West: Sections 19 through 36 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 Township 2 South Range 44 West: Sections 3 through 6 Range 45 West: Section 7: W½, Section 18: W½, Section 19: All Range 46 West: Sections 1 through 24 Range 47 West: All Range 48 West: All Township 3 South Range 48 West: All Township 4 South Range 48 West: All Within the WLR Area, operators may conduct drilling operations to the Niobrara Formation as follows:

(1) Four (4) Niobrara Formation wells may be drilled in any quarter section.

(2) No more than one (1) well may be located in any quarter quarter section.

(3) No minimum distance shall be required between wells producing from the Niobrara Formation in any quarter section.

(4) Wells shall be located at least three hundred (300) feet from the 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.

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.

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).

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.

e. Well exception locations to this WLR shall be subject to the provisions of Rule 318.c.

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 established drilling and spacing units recognizing the owner’s right to apply to the COGCC to resolve any outstanding correlative rights issues.

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.

(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. Temporary Abandonment.

(1) A well may be 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 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 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 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 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 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 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 326, 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 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, taking into consideration cost-effectiveness and technical feasibility 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 Director pursuant to Rule 324D. 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 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 activities.

d. No injection shall be authorized pursuant to Rule 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 141, or may otherwise adversely affect the health of persons. An underground source of drinking water is an aquifer or its portion:

(1) A which supplies any public water system; or B which contains a sufficient quantity of ground water to supply a public water system; and

1. (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:

1. A. It is mineral, hydrocarbon or geothermal energy producing, or can be demonstrated by a person filing an application pursuant to Rule 325, 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 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;

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.

(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 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 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:

1. 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 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:

1. A. Cementing records which shall only be valid for injection wells in existence prior to July 1, 1986;
2. B. Tracer surveys;
3. C. Cement bond log or other acceptable cement evaluation log;
4. 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:

1. 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.
2. 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:

1. 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.
2. 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 oil- level 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.

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.

b. Temperature Correction. The observed volume of oil corrected for impurities shall be further corrected to the standard volume of sixty degrees fahrenheit (60°F) in accordance with ASTM D- 1250 Table 7, or any close approximation thereof approved by the Director.

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 close approximation thereof approved by the Director.

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).

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).

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).

g. Sales Reconciliation. RESERVED 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.

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).

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).

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.

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).

e. Sales Reconciliation. RESERVED 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.

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 a building unit, water well or spring, unless by special written permission of the surface owner or lessee, according to the following minimum setback distances:

CHARGES IN LBS. CHARGES IN LBS. UP MINIMUM SETBACK GREATER THAN TO AND INCLUDING 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 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:

1. 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.
2. 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.
3. 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.
4. 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.
5. 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.

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 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.

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.

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 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:

1. 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;
2. 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;
3. 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;
4. 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;
5. 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);
6. F. a description of any proposed stimulation program;
7. 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 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 the rules, regulations, or orders, from which it seeks a variance, including, without limitation, securing 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) copies of a typewritten or printed petition which shall be titled “application.” The 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, each 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.

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 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:

1. A. The operator;
2. B. The surface owner, solely to raise alleged noncompliance with Commission rules or statute, or to allege potential adverse impacts to public health, safety, and welfare, including the environment and wildlife resources, that are within the Commission’s jurisdiction to remedy;
3. 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;
4. D. The Colorado Department of Public Health and Environment, solely to raise issues relating to protection of health, safety, and welfare of the general public and the environment in the conduct of oil and gas operations; 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.

(10) For purposes of seeking relief or a ruling from the Commission on any other matter not described in (1) through (9) 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 Act 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 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 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.

e. 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, first-class 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.

f. 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.

g. 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.

h. 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) 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.

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 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 5 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

1. (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 Environment, and the Colorado Division of Wildlife of applications made under subsections b.(1) and (3) 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 applications that would result in more than one (1) well site or multi-well site per forty (40) acre nominal governmental quarter- quarter 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” ).

b. Local public forum.

(1) The rules and regulations of the Commission as they are applied to oil and gas operations are expected to adequately address impacts to 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 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 pursuant to Rule 503.c.

1. A. A local public forum shall be convened on the Commission's own motion, or upon request from the local governmental designee or the applicant.
2. 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:
   1. (i) The size of the application area and the number and density of surface location requested;
   2. (ii) The population density of the application area;
   3. (iii) The distribution of Indian, federal and fee lands within the application area;
   4. (iv) The level of current or past public interest in increased well density in the vicinity of the application area;
   5. (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 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 circulation 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 public health, safety, and welfare, including the environment and wildlife resources that are not addressed by the rules or the Proposed Plan.

(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 Commission 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 location reasonably proximate to the lands affected by the application.

f. Conduct of the local public forum.

(1) A Hearing Officer shall preside over the local public forum. The 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 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 public health, safety, and welfare, including the environment and wildlife resources. Issues raised in the local public forum may include the following:

(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 Hearing Officer 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 on the Commission website. 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 Hearing Officer 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:

1. A. Approve the application without condition;
2. B. Approve the application with conditions based on the technical testimony presented at the hearing on the application;
3. 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 public health, safety or welfare, including the environment and wildlife resources;
4. 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.

(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.

j. Public issues hearing .

Upon a request by an applicant, protestant, or intervenor, 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 public health, safety and welfare, including the environment and wildlife resources, that are within the Commission's jurisdiction to remedy;

(2) That the potential impacts were not adequately addressed by:

1. 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 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:

1. 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 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.
2. 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 public health, safety, and welfare, including the environment and wildlife resources.

(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 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. 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:

1. 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.
2. 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 public health, safety and welfare, including the environment and wildlife resources, 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:
   1. i. That the public issues raised by the application 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 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.
3. 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 discretion. The Commission, at its discretion, may limit the scope of the permissive intervenor's participation at the hearing.

(3) The pleading shall include:

1. A. A general statement of the factual or legal basis for the protest or intervention;
2. B. The relief requested;
3. C. A description of the intended presentation including a list of proposed witnesses;
4. 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 thirteen (13) 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.

f. 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 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 a. If the matter is uncontested, the applicant may request, and the Director may recommend, approval without a hearing based on review 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. 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:

1. 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);
2. 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;
3. 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;
4. 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;
5. 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:

1. A. Written request for approval;
2. B. Written testimony;
3. 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:

1. A. Two (2) sets of resumes/curricula vitae for the witnesses;
2. 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;
3. 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:

1. A. Written request for approval;
2. B. Written testimony;
3. C. Summary of testimony; and D. Draft proposed order.

512. COMMISSION MEMBERS REQUIRED FOR HEARINGS AND/OR DECISIONS Five (5) 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. 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. RESERVED 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.

(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:

1. 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 prejudice 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.

(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:

1. 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.
2. 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.
3. C. Whether the potential conflict will result in the Commissioner or Hearing Officer having an unalterably 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;

(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 cross- examine 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.

(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 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 the consent agenda shall be voted on together, without deliberation and without the necessity of reading the individual items. However, 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 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

1. (OFV) in accordance with this rule.

(5) NOAV process.

1. A. An NOAV issued by the Director shall be served on the operator or the operator's designated agent by personal delivery or by certified mail, return receipt requested.
2. B. The NOAV does not constitute final agency action for purposes of judicial appeal.
3. C. 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 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 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 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.

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 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:

1. 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.
2. 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 by a complainant. Unless the operator so agrees, such AOC shall not constitute an admission of the alleged violation. If 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, such 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, on the operator or the operator's designated agent 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 hearing, 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:

(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 RULE NUMBER BASE FINE 205 $1000 206 $1000 207 $1000 208 $1000 209 $1000 210 $500 RULE NUMBER BASE FINE 301 $1000 302 $1000 303 $1000 305 $1000 306 $1000 307 $500 308 $1000 309 $1000 310 $1000 311 $500 312 $500 313 $500 313A $1000 314A $500 315 $500 316A $1000 316B $1000 317 $1000 317A $1000 317B $1000 318 $1000 319 $1000 320 $1000 321 $1000 322 $1000 323 $1000 324 $1000 325 $1000 326 $1000 327 $1000 328 $1000 329 $1000 330 $1000 331 $1000 332 $1000 333 $1000 341 $1000 RULE NUMBER BASE FINE 401 $1000 403 $1000 404 $1000 405 $500 RULE NUMBER BASE FINE 602 $1000 603 $1000 604 $1000 606A $1000 606B $1000 607 $1000 608 $1000 RULE NUMBER BASE FINE 703 $1000 704 $1000 705 $1000 706 $1000 707 $1000 708 $1000 709 $1000 711 $1000 712 $1000 RULE NUMBER BASE FINE 802 $1000 803 $500 804 $500 805 $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.

(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 violator.

(7) The 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 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.

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.

c. Potentially responsible parties shall provide to the Commission or Director such information as the Commission or Director may reasonably require in making such determination.

d. The Commission shall make the determination under this section without regard to any contractual assignments of liability or other legal defenses between parties.

e. 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.

f. 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.

g. 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 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).

b. Whenever the Commission or the Director has evidence that an operator is responsible for a pattern of violation 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 demonstrates 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.

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 Hearing Officer.

i. At any prehearing conference, the following information may be required:

(1) An exchange and acceptance of service of exhibits proposed to be offered in evidence, and establishment of a list of exhibits to be offered;

(2) Establishment 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 Hearing Officer, 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 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.

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 any stipulations;

(5) Opening statement by the applicant;

(6) Opening statements by the respondent (and intervenor, 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.

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;

(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.

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. Initiation of rulemaking. The Commission may 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 prior to the hearing and as otherwise specified in the Administrative Procedure Act, C.R.S. §24-4-103.

d. 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.

e. 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.

f. 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 g. Conduct of rulemaking hearings.

(1) The Commission encourages any person to participate at rulemaking hearings. The times at which the public may participate 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.

(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 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 owner within a drilling and spacing unit established by Commission order fails or refuses to agree to bear 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.

b. An owner shall be deemed a nonconsenting owner in the area to be pooled if, 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.

c. 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 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 treatment or significant damage to equipment or the wellsite shall be reported to the Director 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) At 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 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 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 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 Series 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, or associated on-site production equipment shall be located not less than three hundred fifty (350) feet from any building unit. 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):

1. i. Rig with Kelly. Double ram with blind ram and pipe ram; annular preventer or a rotating head.
2. ii. Rig without Kelly. 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.
3. 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.
4. C. Pit level indicators. Pit level indicators shall be used.
5. 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.

1. 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 a 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 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. No more than two (2) crude oil or condensate storage tanks shall be located within a single berm. All berms and containment devices shall be inspected at regular intervals and 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 (NFPA) 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 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.

(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 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.

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. 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:

1. A. Underwriters Laboratories, Inc., No. UL-142, “Standard for Steel above ground Tanks for Flammable and Combustible Liquids” ;
2. B. American Petroleum Institute Standard No. 650, “Welded Steel Tanks for Oil Storage” ;
3. C. American Petroleum Institute Standard No. 12B, “Bolted Tanks for Storage of Production Liquids” ;
4. 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.

1. A. Tanks less than three thousand (3,000) barrels capacity shall be located at least three
   1. (3) feet apart.
2. B. Tanks three thousand (3,000) or more barrels capacity shall be located at least one- sixth (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.

(3) At the time of installation, tanks shall be a minimum of two hundred (200) feet from any building unit.

(4) Berms or other secondary containment devices shall be constructed around crude oil, condensate, and produced water tanks 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. Berms and secondary containment devices shall be inspected at regular intervals and maintained in good condition. No potential ignition sources shall be installed inside the 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, building units, or well defined normally occupied outside areas.

(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 its 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, 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:

(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.

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 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, 25-7-101, 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.

(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 one-quarter (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 one-quarter (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, 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 “post- completion” 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 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 reliable evidence such as 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 each.

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. 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, §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(13), 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 Indian 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 an amount equal to the estimated cost necessary 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, 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 ten thousand dollars ($10,000) 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 per-well amount, an operator may submit statewide blanket financial assurance in the amount of sixty thousand dollars ($60,000) 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 ten thousand dollars ($10,000) 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 ten thousand dollars ($10,000) 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.

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. General Liability Insurance .

All operators shall maintain general liability insurance coverage for property damage and bodily injury to third parties 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 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 the Oil and Gas Conservation and Environmental Response Fund 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, 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 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/ 55 db(A) 50 db(A)

Rural 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 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) = db(A) – 20 x log (distance 2/distance 1)

DISTANCE 2 DISTANCE 1 10 (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 twenty- five (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 building units.

f. All facilities within four hundred (400) feet of 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 building units within seven (700) hundred feet.

804. VISUAL IMPACT MITIGATION Production facilities, regardless of construction date, which are observable from any public highway shall be painted with uniform, non-contrasting, non-reflective 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 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.

1. 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.
2. 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.

1. 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.
2. 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.
3. 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.
4. D. Pits. Pits constructed after May 1, 2009 on federal land 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 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.
5. 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.

1. A. Green completion practices are required on oil and gas wells where reservoir pressure, formation productivity, and wellbore conditions 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.
2. B. Green completion practices shall include, but not be limited to, the following emission reduction measures:
   1. 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.
   2. 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 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 tanks for safety purposes until flammable gas is encountered.
   3. 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.
   4. 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.
   5. 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 as a safety measure during upset conditions and in accordance with all other applicable laws, rules, and regulations.
3. 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.
4. 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 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.

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 operator to 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 hydrogeologic data 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 submit data evaluated and analysis used in the determination to the Director.

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 concentration levels in Table 910-1, with consideration to WQCC standards and classifications.

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, 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. 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.

c. Any accumulation of oil or condensate 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 oil or condensate to accumulate in a pit. This requirement is not applicable to properly permitted and properly fenced, lined, and netted skim pits that are designed, constructed, and operated to prevent impacts to wildlife, including migratory birds.

d. 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 animals, or members of the general public, operators shall install appropriate netting or fencing.

e. Pits used for a period of no more than three (3) years , or more than three (3) years if the Director has issued a variance, for storage, recycling, reuse, treatment, or disposal of E&P waste or fresh water, as applicable, may be permitted in accordance with Rule 903 to service multiple wells, subject to Director approval.

f. Unlined pits shall not be constructed on fill material.

g. 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 appropriate 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 pits:

(1) All production pits.

(2) Special purpose pits except those reported under Rule 903.b.(1) or Rule 903.b.(2).

(3) Drilling pits designed for use with fluids containing hydrocarbon concentrations exceeding 10,000 ppm TPH or chloride concentrations at total well depth exceeding 15,000 ppm.

(4) Multi-well pits containing produced water, drilling fluids, or completion fluids that will be recycled or reused, except where reuse consists only of moving drilling fluids from one

1. (1) oil and gas location to another such location for reuse there.

b. An Earthen Pit Report/Permit, Form 15, shall be submitted within thirty (30) calendar days after construction for the following:

(1) Special purpose pits used in the initial phase of emergency response.

(2) Flare pits where there is no risk of condensate accumulation.

c. An Earthen Pit 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.(3).

d. An Earthen Pit 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.

e. The Director shall endeavor to review any properly completed Earthen Pit Report/Permit, Form 15, within thirty (30) calendar days after receipt. In order to allow adequate time for pit permit review and approval, operators shall submit an Earthen Pit Report/Permit, Form 15, at the same time as the 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. Pits that were constructed before May 1, 2009 on federal land, or before April 1, 2009 on other land, shall comply with the rules in effect at the time of their construction. 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:

(1) Drilling pits designed for use with fluids containing hydrocarbon concentrations exceeding 10,000 ppm TPH or chloride concentrations at total well depth exceeding 15,000 ppm.

(2) Production pits , 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 to such pits in Washington, Yuma, Logan, Morgan, Huerfano, or Las Animas Counties constructed before May 1, 2011.

(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 where reuse consists only of moving drilling fluids from one oil and gas location to another such location for reuse there. Subject to Rule 901.c, this requirement shall not apply to multi-well pits used to contain produced water in Washington, Yuma, Logan, Morgan, Huerfano, or Las Animas Counties constructed before May 1, 2011.

(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, hydrocarbons, aqueous acids, alkali, fungi or other substances in the produced water.

(2) All pit lining systems shall be designed, constructed, installed, and maintained in accordance with the manufacturers' specifications and good engineering practices.

(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.

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) Liners shall have a minimum thickness of twenty-four (24) 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 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 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.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.

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, 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 emergency pits 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.

(1) Operators shall ensure that soils and ground water meet the 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:

1. A. Synthetic liner disposal. Liner material shall be removed and disposed in accordance with applicable legal requirements for solid waste disposal.
2. 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.

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. 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 resources . 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 concentration levels in Table 910-1, with consideration to WQCC ground water standards and classifications.

b. Reportable spills and reporting requirements for spills/releases.

(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.

(2) Spills/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 twenty-four (24) hours after discovery.

(3) Spills/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

1. (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 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. When threatened or actual significant adverse environmental impacts on any air, water, soil or other environmental resource from a spill/release exists or when necessary to ensure compliance with the concentration 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.

e. Spill/release prevention.

(1) Secondary containment . Secondary containment that was constructed before May 1, 2009 on federal land, or before April 1, 2009 on other land, shall comply with the rules in effect at the time of construction. Secondary containment constructed on or after May 1, 2009 on federal land, or on or after April 1, 2009 on other land shall be constructed or installed around all tanks containing oil, condensate, or produced water with greater than 3,500 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 tank and containment requirements under Rules 603. and 604. This requirement shall not apply to water tanks with a capacity of 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 concentration 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.

(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 that is transported off-site shall maintain, for not less than five (5) years, copies of each invoice, bill, or ticket and such other records as necessary to document the following requirements A through F:

1. A. The date of the transport;
2. B. The identity of the waste generator;
3. C. The identity of the waste transporter;
4. D. The location of the waste pickup site;
5. 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:

1. A. Injection into a Class II well, permitted in accordance with Rule 325.;
2. B. Evaporation/percolation in a properly permitted pit;
3. C. Disposal at permitted commercial facilities;
4. D. Disposal by roadspreading on lease roads outside sensitive areas for produced waters with less than 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, and the adjacent soils shall meet the concentration levels in Table 910-1. Flowback fluids shall not be used for dust suppression.
5. E. Discharging into state waters, in accordance with the Water Quality Control Act and the rules and regulations promulgated thereunder.
   1. 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.
   2. 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.
6. 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). 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) Recycling and reuse . Drilling pit contents may be recycled to another drilling pit for reuse consistent with Rule 903.

(2) Treatment and disposal. Drilling fluids may be treated or disposed as follows:

1. A. Injection into a Class II well permitted in accordance with Rule 325;
2. 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.

(3) Additional authorized disposal of water-based bentonitic drilling fluids. Water-based bentonitic drilling fluids may be disposed as follows:

1. A. Drying and burial in 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:
   1. i. Applicability. Acceptable methods of land application include, but are not limited to, production facility construction and maintenance, and lease road maintenance.
   2. 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 application. The resulting concentrations shall not exceed those in Table 910-1.
   3. iii. Surface owner approval. Operators shall obtain written authorization from the surface owner prior to land application of water-based bentonitic drilling fluids.
   4. 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.
   5. v. Approval. Prior Director approval is not required for reuse of water-based bentonitic drilling fluids for land application as a soil amendment.

e. Oily waste. Oily waste includes those materials containing crude oil, condensate or other E&P waste, such as soil, frac sand, drilling fluids, and pit sludge that contain hydrocarbons.

(1) Oily waste may be treated or disposed as follows:

1. A. Disposal at a commercial solid waste disposal facility;
2. B. Land treatment onsite; or C. Land treatment at a centralized E&P waste management facility permitted in accordance with Rule 908.

(2) Land treatment requirements:

1. A. Free oil shall be removed from the oily waste prior to land treatment.
2. B. Oily waste shall be spread evenly to prevent pooling, ponding, or runoff.
3. C. Contamination of stormwater runoff, ground water, or surface water shall be prevented.
4. D. Biodegradation shall be enhanced by disking, tilling, aerating, or addition of nutrients, microbes, water or other amendments, as appropriate.
5. E. Land-treated oily waste incorporated in place or beneficially reused shall not exceed the concentrations in Table 910-1.
6. F. When a threatened or significant adverse environmental impact from onsite land treatment exists, operators shall submit a Site Investigation and Remediation Workplan, Form 27, for approval by the Director. Treatment shall thereafter be completed in accordance with the workplan and Rules 909. and 910.
7. 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.

1. (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 not 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 non- E&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 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. 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.

1. 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.
2. 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.
3. 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 prevent access to the centralized facility by wildlife or domestic animals.
4. 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.
5. 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, twenty- four (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.

(7) Facility design and engineering. Facility design and engineering data, including plans and elevations, design basis, calculations, and process description.

1. A. Geologic data, including, but not limited to:
   1. i. Type and thickness of unconsolidated soils;
   2. ii. Type and thickness of consolidated bedrock, if applicable;
   3. iii. Local and regional geologic structures; and iv. Any geologic hazards that may affect the design and operation of the facility.
2. B. Hydrologic data, including, but not limited to:
   1. i. Surface water features within two (2) miles;
   2. ii. Depth to shallow ground water and major aquifers;
   3. iii. Water wells within one (1) mile of the site boundary and well depth, depth to water, screened intervals, yields, and aquifer name;
   4. iv. Hydrologic properties of shallow ground water and major aquifers including flow direction, flow rate, and potentiometric surface;
   5. v. Site location in relation to the floodplain of nearby surface water features;
   6. vi. Existing quality of shallow ground water; and vii. An evaluation of the potential for impacts to nearby surface water and ground water.
3. C. Engineering data, including, but not limited to:
   1. i. Type and quantity of material required for use as a liner, including design components;
   2. ii. Location and depth of cut for liners;
   3. iii. Location, dimensions, and grades of all surface water diversion structures;
   4. 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:

1. A. A detailed description of the method of treatment, loading rates, and application of nutrients and soil amendments;
2. B. Dust and moisture control;
3. C. Sampling;
4. D. Inspection and maintenance;
5. E. Emergency response;
6. F. Record-keeping;
7. G. Site security;
8. H. Hours of operation;
9. I. Noise and odor mitigation; and J. Final 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.

1. A. Water Wells.

   Water samples shall be collected from water wells known to the operator or registered with the Colorado State Engineer 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 identify and 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.

2. B. Site-specific monitoring wells.
   1. i. Where applicable, the Director shall require ground water monitoring to ensure compliance with the concentration levels in Table 910-1 and 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).
   2. ii. 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.

(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. Operators shall use reasonable good faith efforts to obtain access to such surface water for the purpose of collecting water samples. If access cannot be obtained, then the operator shall notify the Director of the surface water for which access was not obtained and sampling of such surface water by the operator shall not be required. Not conducting sampling because access to surface water cannot be obtained shall not be grounds for denial of the proposed facility.

(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 concentration 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 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.

(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:

1. 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.
2. B. 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.

h. Operators may be subject to local requirements for zoning and construction of facilities and shall provide copies of any 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); investigation, 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. Sampling 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 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 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 concentrations in Table 910-1 shall be remediated. Ground water that does not meet 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.

e. Closure.

(1) Remediation and reclamation shall be complete upon compliance with the 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:

1. 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.
2. 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. CONCENTRATIONS AND SAMPLING FOR SOIL AND GROUND WATER a. Soil and groundwater concentrations. The 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 concentration levels in Table 910-1.

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.
2. 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.
3. 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 concentrations in Table 910-1.
4. 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.

1. 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.
2. 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.
3. 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.
4. D. Reporting. Soil Analysis Report, Form 24, shall be used when the Director requires results of soil analyses.
5. 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 level in Table 910-1, the sodium adsorption ratio (SAR) shall also be determined.
6. F. Soil impacted by hydrocarbons. For impacts to soil due to hydrocarbons, samples shall be analyzed for TPH.

(4) Ground water sampling and analysis.

1. A. Applicability. Operators shall collect and analyze representative samples of ground water in accordance with these rules under the following circumstances:
   1. (i) Where ground water contamination is suspected or known to exceed the concentrations in Table 910-1;
   2. (ii) Where impacted soils are in contact with ground water; or (iii) Where impacts to soils extend down to the high water table.
2. 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.
3. 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.
4. D. Reporting. Water Analysis Report, Form 25, shall be used when the Director requires results of water analyses.
5. E. Impacted ground water. Where ground water contaminants exceed the 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 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:

1. A. Lined production pits and lined special purpose pits constructed after July 1, 1995.
2. 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:

1. A. Unlined production pits and special purpose pits in sensitive areas constructed prior to July 1, 1995, and not closed by December 30, 1997.
2. 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

1. (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 safety of the well site personnel and the public.

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 CONCENTRATION LEVELS 1 Contaminant of Concentrations Concern . .

Organic Compounds .

in Soil TPH (total volatile and 500 mg/kg extractable petroleum hydrocarbons)

Benzene 2

1. 0.17 mg/kg

Toluene 2 85 mg/kg Ethylbenzene 2 100 mg/kg Xylenes (total 2 175 mg/kg Acenaphthene 2 1,000 mg/kg Anthracene 2 1,000 mg/kg Benzo(A)anthracene 2

1. 0.22 mg/kg

Benzo(B)fluoranthene 2

1. 0.22 mg/kg

Benzo(K)fluoranthene 2

1. 2.2 mg/kg

Benzo(A)pyrene 2

1. 0.022 mg/kg

Chrysene 2 22 mg/kg Dibenzo(A,H)anthracene 2

1. 0.022 mg/kg

Fluoranthene 2 1,000 mg/kg Fluorene 2 1,000 mg/kg Indeno(1,2,3,C,D)pyrene 2

1. 0.22 mg/kg

Napthalene 2 23 mg/kg Pyrene 2 1,000 mg/kg Organic Compounds .

in Ground Water Benzene 3 5 µg/l Toluene 3 560 to 1,000 µg/l Ethylbenzene 3 700 µg/l Xylenes (Total) 3,4 1,400 to 10,000 µg/l Inorganics in Soils .

Electrical Conductivity < 4 mmhos/cm or 2x (EC) background Sodium Adsorption Ratio 5 < 12 (SAR)

pH 6-9 Inorganics in .

Ground Water Total Dissolved Solids 3 < 1.25 x background (TDS)

Chlorides 3 < 1.25 x background Sulfates 3 < 1.25 x background Metals in Soils .

Arsenic 2

1. 0.39 mg/kg

Barium (LDNR True 2 15,000 mg/kg Total Barium)

Boron (Hot Water 3 2 mg/l Soluble)

Cadmium 3,6 70 mg/kg Chromium (III) 2 120,000 mg/kg Chromium (VI) 2,6 23 mg/kg Copper 2 3,100 mg/kg Lead (inorganic) 2 400 mg/kg Mercury 2 23 mg/kg Nickel (soluble salts) 2,6 1,600 mg/kg Selenium 2,6 390 mg/kg Silver 2 390 mg/kg Zinc 2,6 23,000 mg/kg Liquid .

Hydrocarbons in Soils and Ground Water Liquid hydrocarbons Below detection level including condensate and oil 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. 2 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, site-specific standards for the chemical, the site-specific standards shall apply instead of these statewide standards. 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. 1000-SERIES RECLAMATION REGULATIONS 1001. INTRODUCTION 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 Series rules, when the Director has reasonable cause to believe that a proposed oil and gas operation could result in a significant adverse environmental 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.

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), 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, notwithstanding 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 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. 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 topsoil horizon or the top six (6) inches, whichever is deeper, and mark or document stockpile locations to facilitate subsequent reclamation. When separating the 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 activity 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, deep 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.

e. Surface disturbance minimization.

(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, removal of surface materials, and degradation due to contamination.

(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.

(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. 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 and 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 complement 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 site- specific 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:

1. 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.
2. 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.
3. 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.
4. 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 site conditions and controls are adequate and in place to effectively manage stormwater.
5. 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).
6. 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.

1. 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:
   1. i. Transport of chemicals and materials, including loading and unloading operations;
   2. ii. Vehicle/equipment fueling;
   3. iii. Outdoor storage activities, including those for chemicals and additives;
   4. iv. Produced water and drilling fluids storage;
   5. v. Outdoor processing activities and machinery;
   6. vi. Significant dust or particulate generating processes;
   7. vii. Erosion and vehicle tracking from well pads, road surfaces, and pipelines; viii. Waste disposal practices;
   8. ix. Leaks and spills; and x. Ground-disturbing maintenance activities.
2. 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. Documentation shall include a description of the BMPs selected to ensure proper implementation, operation, and maintenance.
3. 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. 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 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, 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 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 , weather permitting .

(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%) 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 as free of all undesirable plant species designated to be noxious weeds 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. 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:

(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 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 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 pre- disturbance 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. Material.

(1) Materials for pipe and other components of pipelines shall be:

1. A. Able to maintain the structural integrity of the pipeline under temperature, pressure, and other conditions that may be anticipated;
2. B. Compatible with the substances to be transported.
3. 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.

b. 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.

c. 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.

d. 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.

e. 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.

(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 (¼) 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. 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 and attached as Appendices VII and VIII 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 or restricted surface occupancy area, in an order increasing well density, or in a basin-wide order involving wildlife resource issues 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 or a restricted surface occupancy area , 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;

(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 biologically appropriate 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 sharp-tailed grouse production areas, greater or Gunnison sage grouse production areas, black-footed ferret release 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 AND RESTRICTED SURFACE OCCUPANCY AREAS a. General Operating Requirements. Within sensitive wildlife habitat and restricted surface occupancy areas , 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 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.

(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:

1. 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) To minimize adverse impacts to wildlife resources, 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 extent practicable, consistent with these rules, an operator’s operational requirements, and any requirements imposed by federal and state land management agencies, local government regulations, and surface use agreements and other surface owner requirements , 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 maintenance, repairs and replacements, emergency operations, reclamation activities, or habitat improvements are not prohibited in Restricted Surface Occupancy areas. Notwithstanding the foregoing, non-emergency workovers, including uphole recompletions, may be performed with prior approval of the Director on a schedule that minimizes adverse impacts to the species for which the restricted surface occupancy area exists.

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 begun prior to May 1, 2009 on federal land or April 1, 2009 on all other land, pursuant to Rule 306.c or Rule 216 . Statement of Basis, Specific Statutory Authority, and Purpose New Rules and Amendments to Current Rules of the Colorado Oil and Gas Conservation Commission, 2 CCR 404-1 This statement sets forth the basis, specific statutory authority, and purpose for new rules and amendments to the Rules and Regulations and Rules of Practice and Procedure (“Rules” ) promulgated by the Colorado Oil and Gas Conservation Commission (“COGCC” ) on December 11, 2008. These rules are promulgated to protect public health, safety, and welfare, including the environment and wildlife resources, from the impacts resulting from the dramatic increase in oil and gas development in Colorado. They also implement new statutory authority and update existing regulations where appropriate. They are intended to foster the responsible and balanced development of oil and gas resources. Unless otherwise specified, the new rules and amendments become effective on May 1, 2009 on federal land and April 1, 2009 on all other land.

In adopting the new rules and amendments, the Commission relied upon the entire administrative record for this rulemaking proceeding, which formally began in March 2008 and informally began in the summer of 2007. This record includes the proposed rules and numerous recommended modifications and alternatives; thousands of pages of public comment, written testimony, and exhibits; and 12 days of public and party hearings. The Commission spent another 12 days deliberating on the rules before taking final action.

Statutory Authority The additions and amendments to the rules are promulgated pursuant to the authority granted to COGCC by House Bills (“HB” ) 07-1298 and 07-1341, codified at sections 34-60-106 and 34-60-128, C.R.S., of the Oil and Gas Conservation Act (“Act” ). Additional authority for the promulgation of the rules is provided by sections 34-60-102, 34-60-103, 34-60-104, 34-60-105, and 34-60-108, C.R.S. of the Act. The Commission also adopted the following statement of basis and purpose consistent with section 24-4- 103(4), C.R.S., of the Administrative Procedure Act. This statement is hereby incorporated by reference in the rules adopted.

The rulemaking hearing for these rules was held on May 22, 2008 (initial motions); June 10, 2008 (public testimony); June 23-27, 2008 (public and party testimony); June 30-July 1, 2008 (party testimony); July 15-17, 2008 (party testimony); August 19-20, 2008 (deliberations); September 9-11, 2008 (deliberations); September 22-23, 2008 (deliberations); October 26-27, 2008 (deliberations); and December 9-11, 2008 (deliberations).

Purpose Address Growing Impacts of Increase in Oil and Gas Activity A major reason for adopting these regulations was to address concerns created by the unprecedented increase in the permitting and production of oil and gas in Colorado in the past few years. In 1996, the COGCC, through its Director, approved 1,002 applications for permits to drill (“APD” ). In 2004, that number increased to 2,915 approved APDs. In 2007, the COGCC approved 6,368 APDs. The COGCC anticipates that it will approve approximately 7,500 APDs in 2008. This increase in permitting levels generally corresponds to an increase in drilling activity, particularly in the Piceance Basin, where drilling has extended into new areas with more extensive wildlife and water resources, more challenging terrain, and additional people. These increases require the COGCC to re-evaluate its regulatory scheme to ensure that its rules are appropriate for the heightened level and broader geographic extent of development activity in Colorado. In addition, as the level and extent of drilling activity has increased, so has the public concern for the health, safety and welfare of Colorado’s residents. The level of public concern for Colorado’s environment and wildlife resources has also risen with the increase in permitting and drilling over the past few years. With the number of approved APDs increasing by approximately 750% in twelve years (and 257% in just four years) and the public concerns engendered by the increased activity, the COGCC’s re-evaluation was necessary and appropriate. Implement 2007 Legislation In 2007, upon the urging and initiative of the Colorado Department of Natural Resources, the General Assembly passed legislation to increase the Commission's regulatory authority and oversight obligations to better address the potential adverse impacts that can accompany oil and gas development . The General Assembly declared that it is in the public’s interest to foster the responsible, balanced development of Colorado’s oil and gas resources consistent with the protection of public health, safety, and welfare, including protection of the environment and wildlife resources . C.R.S. § 34-60-102(1) (emphasis added).

The new rules comply with the legislative mandate to: (1) foster oil and gas development consistent with the protection of public health, safety, and welfare, including the environment and wildlife resources; (2) promote the conservation of wildlife habitat in connection with the development of oil and gas; and (3) minimize adverse impacts to wildlife resources affected by oil and gas operations and ensure proper reclamation of wildlife habitat. C.R.S. § §34-60-106, 34-60-128. In order to protect the health, safety, and welfare of the general public, the COGCC staff developed the rules in consultation with the Colorado Department of Public Health and Environment (“CDPHE” ). C.R.S. § 34-60-106(11)(a)(II). As directed by the legislature, the rules provide a timely and efficient procedure by which the CDPHE has an opportunity to provide comments during the COGCC’s decision-making process. Id.

In order to minimize adverse impacts to wildlife resources and ensure proper reclamation of wildlife habitat, the COGCC staff developed the rules in consultation with the Colorado Division of Wildlife (“CDOW” ). C.R.S. § 34-60-128(3)(d)(I). As directed by the legislature, the rules: (1) develop a timely and efficient consultation process with the CDOW governing notification and consultation to minimize adverse impacts and other issues relating to wildlife resources; (2) encourage operators to utilize comprehensive drilling plans and geographic area analysis strategies to provide for orderly development of oil and gas fields; and (3) minimize surface disturbance and fragmentation in important wildlife habitat by incorporating appropriate best management practices in certain COGCC orders and decisions. See C.R.S. § 34-60-128(d)(I-III).

Update Existing Rules Where Appropriate The COGCC staff also identified existing rules to update in order to enhance clarity, respond to new information, and reflect current practice and procedure. Although the Commission has annually adopted or amended particular rules, the last set of comprehensive amendments occurred more than a decade ago and various rules had become outdated. For example, before amendment some of the environmental and financial assurance rules no longer adequately addressed current needs and conditions. Similarly, before amendment some of the procedural rules did not reflect current COGCC practices. Therefore, the Commission used this as an opportunity to update existing rules where appropriate. Background Development of the Draft Rules The General Assembly entrusted the Commission with the weighty task of fine-tuning the balancing act between the development of the oil and gas resources and the protection of public health, safety, and welfare, including the environment and wildlife resources. The COGCC staff therefore began the development of the draft rules with the understanding that the continuation of oil and gas development is important to Colorado, as is the protection of Colorado’s citizens and environment from the negative impacts of such development.

In the summer of 2007, staff members of the COGCC, CDPHE, and CDOW met and began identifying specific areas where new COGCC regulations were required to properly address identified problems and implement HBs 07-1298 and 07-1341. In addition, the staff members of the three agencies began contacting individuals who participated in drafting HBs 07-1298 and 07-1341 and other people that either expressed an interest in or were believed to potentially be affected by the proposed rulemaking, including representatives from the oil and gas industry, the environmental community, local governments, federal agencies, sportsmen, and property owners.

In November 2007, the COGCC staff circulated a document entitled “Initial pre-draft rulemaking proposal to implement HBs 07-1298 and 07-1341” (“pre-draft proposal” ) to stakeholders. The COGCC also posted this document on its website. The pre-draft proposal was a conceptual, narrative document, which was intended to frame the issues and facilitate public input prior to development of the draft rules. Once the pre-draft proposal was distributed, all stakeholders and members of the public were given the opportunity to review and comment on the document, and thousands of pages of such comments were received by the COGCC staff. Once the public comment began in December 2007, all public comment pertaining to the rulemaking was posted on the COGCC website as time and resources allowed. To obtain additional public comment prior to development of the draft rules, the COGCC, CDPHE, and CDOW staffs held five meetings in January 2008 in communities significantly affected by oil and gas development. These meetings were held in Parachute, Greeley, Wray, Durango, and Trinidad, and they were collectively attended by approximately 1,700 people. They provided the staffs with substantial additional input on the pre-draft proposal and rulemaking and apprised the public of the rulemaking process.

Also during January and February 2008, the COGCC staff convened nine technical work groups to discuss some 67 issues associated with the pre-draft proposal. These work groups held a total of 37 meetings, which lasted about 150 hours, and were attended by about 250 stakeholders. Through these meetings, the participants shared their perspectives on a range of issues associated with the pre-draft proposal and the rulemaking, including existing problems, regulatory costs and benefits, efficiency and timing concerns, and alternative approaches. All of these meetings were noticed on the COGCC website, and were open to interested members of the public. Through the initial meetings, pre-draft proposal, public meetings, and technical work groups, the COGCC staff received broad stakeholder and public input before the draft rules were prepared and the formal rulemaking process began. Local governments, oil and gas companies, environmental groups, sportsmen, and other members of the public received and took advantage of numerous opportunities to offer input regarding the development of the draft rules. After careful consideration of this input, the COGCC staff in consultation with the CDPHE and CDOW drafted proposed rules which were provided to the Commission and posted on the COGCC website on March 31, 2008 and published in the Colorado Register on April 10, 2008. The draft rules differed substantially from the pre-draft proposal. Of 21 topics addressed in the draft rules, 17 of them reflected significant changes from the pre-draft proposal. Changes were made to simplify requirements, better differentiate between different geologic basins, further minimize adverse impacts to public health, the environment, and wildlife resources, and ensure timely and efficient action. These changes improved the draft rules and better balanced the development of oil and gas with the protection of public health, safety and welfare, including the environment and wildlife resources. Rulemaking Hearing and Development of the Final Rules The COGCC staff submitted its prehearing statement in support of the draft rules on April 18, 2008, which included extensive written testimony and exhibits from COGCC, CDPHE, and CDOW staff. This testimony described the problem each draft rule was designed to address, explained how each proposed change would address the problem and result in greater protection for public health or the environment, and evaluated whether the proposed rule would affect industry’s ability to develop the resource efficiently and whether it would effectively balance development of oil and gas resources with protection of public health, safety, and welfare, including the environment and wildlife resources. Eighty-five different individuals or organizations requested party status to this rulemaking, including government organizations, oil and gas companies, conservation groups, and agricultural associations. These parties filed responsive prehearing statements in May 2008. Their responses included thousands of pages of additional written testimony and exhibits. In addition to filing responsive prehearing statements, these parties to the rulemaking were given numerous opportunities to present witnesses and written materials to the Commission throughout the rulemaking hearing, as described below. On May 16, 2008, the COGCC staff, in consultation with the CDPHE and CDOW, submitted a cost-benefit and regulatory analysis, to provide additional information to the Commission, parties, and public, and to comply with the Administrative Procedure Act, C.R.S. § 24-4-101 et. seq. This 182-page analysis addressed each of the proposed rules and described, inter alia , the likely beneficiaries of the proposed rule and the nature of any anticipated benefit, the likely costs expected to be incurred as a consequence of the proposed rule, and any adverse effects of the proposed rule on small businesses or consumers. For each proposed rule, the cost-benefit and regulatory analysis compared the overall benefits and costs of the proposed rule to alternative approaches and explained why the alternative approaches had been rejected.

The Commission commenced the rulemaking hearing on May 22, 2008 in Denver, reviewing a prehearing order and considering appeals from any party regarding procedural decisions contained therein. The Commission also addressed initial motions filed by the parties, including motions seeking to bifurcate or limit the proceeding. Both staff and parties to the rulemaking subsequently filed rebuttal prehearing statements in early June 2008.

The Commission heard approximately eight hours of public testimony on June 10, 2008 in Grand Junction, Colorado and approximately four hours of public testimony on June 23, 2008 in Denver, Colorado. The Commission began hearing testimony from parties and party witnesses on June 23, 2008 in Denver. For the next six days, the Commission heard testimony from parties or party witnesses, cross- examination by parties, and answers to Commissioner questions from parties or party witnesses. The Commission reconvened for three more days of testimony, cross-examination, and questioning during July 15-18, 2008 in Denver.

Throughout this period, the COGCC staff was in frequent discussion with parties regarding the draft rules. Based upon these discussions and its own further evaluation, the COGCC staff issued clarifications to several of the proposed rules in May and June 2008. In consideration of arguments and alternative proposals contained in the parties' responsive prehearing statements and rebuttal statements, the COGCC staff issued a comprehensive set of suggested revisions to the proposed rules on June 18, 2008. The Commission invited groups of parties to submit alternative language for the proposed rules by July 30, 2008. Each of the party groups submitted alternative language, and some party groups submitted additional material in support of their proposed alternative approaches. The COGCC staff reviewed these submittals and, on August 11, 2008, submitted alternative recommended language for several of the draft rules.

The Commission closed the evidentiary record and commenced deliberations on August 19-20, 2008 in Denver on those rules for which the COGCC staff had developed alternative recommended language. During these deliberations, the Commission initially approved each of these rules, subject to changes provisionally approved in the deliberations. During these two days of deliberations, the Commission gave initial approval to fifty of the proposed rules.

The COGCC staff then reviewed the parties' July 30, 2008 submittals for the balance of the proposed rules and, on September 3-5, 2008, submitted recommended alternative language for each of the remaining draft rules. The Commission conducted deliberations on these draft rules on September 9-11 and 22-23, 2008 and on October 26-27, 2008. During these deliberations, the Commission gave initial approval to the remainder of the proposed rules.

At the conclusion of the initial deliberations, COGCC staff reviewed the transcripts of the proceedings and prepared final rule language. Where the Commission directed the staff to prepare new language for particular rules, the staff gave the parties an opportunity to review and comment to the Director on that new language. On November 7, 2008, the COGCC staff submitted final rule language for the Commission’s review and consideration. The Commission conducted final deliberations on this language and adopted the final rules on December 9-11, 2008.

This was the most extensive rulemaking hearing in the Commission’s history. All told, the Commission held twenty-two days of hearings, with some the days lasting almost twelve hours. The Commission heard approximately twelve hours of public comment by approximately two hundred people. It heard from approximately one hundred sixty party and staff witnesses and heard approximately seventy-five hours of testimony, cross, examination, and answers to Commissioner questions on twelve days of hearings. The Commission also considered more than thirty legal motions and conducted nine days of initial and final deliberations totaling more than seventy additional hours. Throughout the hearing, the Commission listened to all of the witnesses, questioned aspects of witnesses' written testimony, directed its staff to work with parties, and asked clarifying questions as necessary. The Commission repeatedly extended the rulemaking hearing in order to hear additional testimony and argument and conduct additional deliberations. It also directed and approved numerous changes to the draft rules that reflect input from the parties.

The Commission believes that the resulting final rules responsibly address the recent increase in oil and gas development, implement the 2007 legislation, and update the prior rules where appropriate. It also believes that these rules will ensure the protection of the public health, safety and welfare, including the environment and wildlife resources, while also fostering the responsible, balanced development, production, and utilization of oil and gas resources. C.R.S. § 34-60-102(1)(b). These rules will, among other things:

- Provide additional protection for public health and the environment through several new measures. These measures include requirements that operators maintain an inventory of chemicals kept onsite for use downhole, restrict operations in areas near drinking water sources, install emission control devices on certain equipment located near homes, schools, and other occupied buildings, and implement additional stormwater management measures. See Rules 205 , 317B, 805, and 1002; - Minimize adverse impacts on wildlife resources by requiring operators to work with CDOW regarding site-specific mitigation for sensitive wildlife habitat (mostly located in Western Colorado) and to avoid the most critical habitat areas where technically and economically feasible. See Rules 1201-1205 ;

- Provide for consultation with the CDPHE and CDOW in appropriate circumstances. These consultations will result in recommendations to the COGCC Director on appropriate conditions of approval to protect public health, the environment, and wildlife. For wildlife conditions, the Director’s decision will be subject to surface owner consent. See Rules 306, 1202 ;

- Provide for timely efficient permitting through measures such as limiting the duration of CDPHE and CDOW consultation and public comment, expediting approvals under certain circumstances, and Commission review if permitting decisions are not timely issued. The rules also omit earlier proposals to develop an expansive new application form and require wildlife surveys. See Rules 216, 303, 305, 306, and 1201; - Encourage landscape level planning through operator-initiated Comprehensive Drilling Plans, which will facilitate early and collaborative review and in certain circumstances aggregate and expedite regulatory approvals. While such Plans will be optional, the rules contain incentives for their use. See Rule 216 ;

- Provide for enhanced transparency by notifying surface owners, the owners of nearby surface property, local governments, the CDPHE and CDOW, and the public of permit applications and providing them with a minimum 20-day period to submit comments to the Director. See Rule 305 ; and - Avoid a one-size-fits-all approach by tailoring numerous rules to the individual circumstances of the location or region. This includes rules concerning the requirements for compliance checklists, permit applications, notice, drinking water protection, odor control, and wildlife habitat protection. See Rules 206, 303, 305, 317B, 318A, 318B , 805, and 1202- 1205 .

Applicability of Rules to Federal, State and Private Land The rules are grounded in the police powers of the State and are designed to protect Colorado’s public health, safety, and welfare, including its environment and wildlife resources. The Commission believes that such protection is necessary for all lands, regardless of surface ownership. 1 This protection cannot be achieved if it is contingent on surface ownership. Rather, public health, safety, and welfare, including the environment and wildlife resources, are affected by oil and gas operations regardless of who owns the surface. Therefore, the regulatory protections imposed on oil and gas operations by these rules will apply on private, state, and federal land. See Aztec Minerals Corporation v. Romer, 940 P.2d 1025 (Colo. App. 1996) (pursuant to its police power, a governmental entity controls the use of property by the owner for the public good, authorizing its regulation without compensation). See also California Coastal Comm’n v. Granite Rock Co., 480 U.S 572 (1987) (states can impose environmental controls on private mining activities on federally owned land).

1 The COGCC rules, however, are not intended to alter, impair, or negate the provisions of the Memorandum of Understanding between the Colorado Bureau of Land Management and the COGCC dated August 22, 1991. To clarify this intent, the COGCC added language to Rule 201 regarding Indian trust lands and minerals and the Southern Ute Indian Tribe which was developed by COGCC attorneys at the Office of the Attorney General, attorneys for the Southern Ute Indian Tribe, and attorneys for the Bureau of Land Management.

The Act provides that “[t]he Commission has jurisdiction over all persons and property, public and private , necessary to enforce the provisions of this article, and has the power to make and enforce rules, regulations, and orders pursuant to this article, and to do whatever may reasonably be necessary to carry out provisions of this article.” C.R.S. § 34-60-105(1) (emphasis added). The Act also provides that “[a]s to lands of the United States or lands which are subject to its supervision, [the Act] shall apply . . . to carry out the provisions of sections 34-60-106, 34-60-117(4), 34-60-118, and 34-60-122. ” Section 34- 60-106(2)(d), C.R.S., states that the COGCC has the authority to regulate “[o]il and gas operations so as to prevent and mitigate significant adverse environmental impacts on any air, water, soil, or biological resource resulting from oil and gas operations to the extent necessary to protect public health, safety, and welfare, including protection of the environment and wildlife resources, taking into consideration cost- effectiveness and technical feasibility.” Accordingly, COGCC regulations will apply across the board to all lands on which oil and gas operations are occurring , with limited exceptions . 2 2 Although the rules are to apply to federal lands as of May 1, 2009, the COGCC staff will work with the Bureau of Land Management and U.S. Forest Service to attempt to develop a Memorandum of Understanding that clarifies how the rules will apply to federal land and that attempts to avoid duplicative and inconsistent regulation. Additional Action During the rulemaking hearing, the Commission deferred action on a series of subjects to provide additional time for discussion, consideration, and, in some cases, consensus-building. The Commission decided to do this because it believes that spending additional time on these subjects will materially improve the quality of its decisions regarding them.

One subject where the Commission chose to defer action involves the application of these new rules and amendments to projects subject to approval by the Federal Energy Regulatory Commission, to the safety aspects of projects that are regulated by the U.S. Department of Transportation, or to midstream operations until the Commission conducts a further regulatory proceeding to address the manner in which such amendments and new rules shall apply to such projects and operations. Those three categories of projects and operations raise factual and legal issues that are distinct from those involving other oil and gas facilities. Therefore, in the interest of efficiency and timely action, the Commission chose to defer application of the new rules and amendments to such projects and operations, and to defer consideration of certain other proposed rules and amendments regarding such projects and operations specifically, until the Commission can devote its resources to a separate rulemaking to address these topics at a date in the near future.

The Commission also chose to defer action on the following issues: (1) Proposed Rule 521., which involves memoranda of agreements with local governments; (2) setback distances under amended Rule 603.; (3) interim and final reclamation standards under amended Rules 1003 and 1004; (4) development of a list of recommended best management practices for wildlife under new Rule 1202; and (5) expansion of restricted surface occupancy areas to include additional riparian areas under new Rule 1205. During the hearing, the Commission determined that these particular issues should be further developed through a pilot project (memoranda of agreements with local governments) or stakeholder process (setback distances, reclamation standards, best management practices, and restricted surface occupancy area expansion). Because of the complex and important nature of these issues, the Commission wanted them to receive additional attention and consideration before action is taken upon them. Further information on future action regarding these issues is set forth below under the respective rules involved. Amendments and Additions to Rules by Series The amendments include those that correct any typographical and grammatical errors. In addition, substantive amendments and additions to 2 CCR 404-1 were made. The general authority for adoption of these rules is set out in the Statutory Authority section above and is generally applicable to all amendments and new rules. The most specific authority and a summary of the purpose for each rule change is set forth below. References to particular factors or testimony is intended to be illustrative and not comprehensive.

100-Series Definitions As a general note, the revised 100-Series contains many definitions that occur throughout the existing rules and Act that have been moved to, or included in, this Series to improve the usefulness and readability of the Series. Some of these definitions reflect terms used in HBs 07-1298 and 07-1341. Others define terms that are used in new or amended rules that implement these statutes. Amendments The following definitions were substantively amended:

1. Cease and Desist Order:

Basis: The statutory basis for this amendment is section 34-60-121(5), C.R.S. Purpose: The purpose of this amendment is to clarify that both the Director of the COGCC and the full Commission can issue a cease and desist order under certain circumstances. This is consistent with the statutory language of section 34-60-121(5), C.R.S.

2. Centralized E&P Waste Management Facility Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: The purpose of this amendment is to update and clarify the definition consistent with HB 07-1341.

3. Completion Pits Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: This amendment clarifies that completion pits may be used to contain both fluids and solids produced during initial completion procedures.

4. Emergency Pits Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: This definition was amended to clarify the intent of the amended 900-Series Rules.

5. Flowlines Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: The purpose of this amendment is to expand the definition of flowlines, in the case of water lines, to include the permitted surface water discharge point. This expansion is more protective of the environment and is consistent with the direction from HB 07-1341.

6. Intervenor Basis: The statutory bases for this amendment are sections 34-60-108, 34-60-106(11)(a)(II), and 34-60-128(3)(d), C.R.S.

Purpose: The purpose of this amendment is to include CDPHE and CDOW as Intervenors to COGCC hearings. CDPHE can intervene to raise environmental or public health, safety and welfare concerns. CDOW can intervene to raise concerns about adverse impacts to wildlife resources. Based on requirements to consult with these agencies, COGCC chose to grant them intervener status as a matter of right.

7. Multi-Well Pits Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: This definition was amended to be consistent with the intent of the amended 900 Series rules and to better distinguish multi-well pits from centralized E&P waste management facility pits. The Commission wishes to emphasize that the terms “treatment, storage and disposal” used in this definition include recycling or reuse. 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.

8. Production Pits Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: This definition was amended to update and clarify the definition of production pits.

9. Reserve Pits Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: The purpose of this amendment is to expand the definition of reserve pits to include pits used to contain E&P waste generated during initial completion procedures.

10. Responsible Party Basis: The statutory basis for this amendment is section 34-60-124(8)(a), C.R.S. Purpose: The purpose of this amendment is to clarify that the only entities that can be identified as responsible parties for certain actions are owners and operators of oil and gas operations.

11. Sensitive Area Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: This amendment clarifies and expands this definition to include certain additional areas that warrant additional protection for water resources.

12. Skimming/Settling Pits Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: This definition was amended to update and clarify the meaning of this term.

13. Well Site Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: The purpose of this amendment is to expand the definition of well site to include the associated pad of any oil well, gas well, or injection well. Additions to the 100-Series The following definitions were added to the 100 Series of rules:

1. Ancillary Facilities Basis: The statutory bases for this addition are sections 34-60-106(11)(a)(II) and 34-60-128(3) (d), C.R.S.

Purpose: The purpose of this addition is to clarify that virtually all facilities associated with oil and gas production are considered ancillary facilities by the COGCC, and are subject to regulation by the COGCC.

2. Best Management Practices Basis: The statutory bases for this addition are sections 34-60-106(11)(a)(II), 34-60-128(3)(c), and 34-60-128(3)(d), C.R.S.

Purpose: HB 07-1298 required the COGCC to address by rulemaking the use of best management practices to conserve wildlife resources. In addition, “best management practices” is a commonly used term for a variety of techniques selected by operators to minimize impacts to public health, welfare and the environment. A number of provisions in these rules (including those for public drinking water protection and stormwater management) establish requirements for operators to select appropriate best management practices. Therefore, this definition was added to define the term, and is intended to include siting, design, maintenance, and operating practices.

3. Chemical Basis: This statutory basis for this addition is section 34-60-106(11)(a)(II), C.RS. Purpose: Rule 205. discusses chemicals. This definition was added to define that term.

4. Chemical Inventory Basis: This statutory basis for this addition is section 34-60-106(11)(a)(II), C.RS. Purpose: Amended Rule 205. requires operators to maintain a chemical inventory. This definition makes clear what that term means.

5. Chemical Product Basis: This statutory basis for this addition is section 34-60-106(11)(a)(II), C.RS. Purpose: Rule 205. refers to chemical products. This definition was added to clarify that term.

6. Classified Water Supply Segment Basis: This statutory basis for this addition is section 34-60-106(11)(a)(II), C.RS. Purpose: Rule 317B is a new rule for protecting public drinking water systems. This definition was added to establish the scope of this rule. It creates the basis for protection zones that, when combined with performance requirements applicable within certain distances of classified water supply segments, will ensure adequate protection of public drinking water supplies.

7. Compliance Checklist Basis: This statutory basis for this addition is section 34-60-106(11)(a)(II), C.RS. Purpose: Rule 206. was amended to provide operators and the COGCC with a tool for ensuring that operators pay regular attention to their compliance status with respect to certain COGCC Rules. Specifically, the Compliance Checklist is intended to remind and assist the operator and COGCC in assuring compliance with the applicable regulatory requirements involving public health and environmental protection. This definition was added to define Compliance Checklist for this purpose.

8. Comprehensive Drilling Plan Basis: The statutory bases for this addition are sections 34-60-106(11)(a)(II) and 34-60-128(3)(d) (II), C.R.S.

Purpose: HB 07-1298 required the COGCC to address by rulemaking the use of Comprehensive Drilling Plans. In response, the Commission adopted Rule 216., which provides for the preparation and approval of such plans. This definition was added to clarify the meaning of that term.

9. Container Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: This definition was added to clarify the difference in the labeling requirements under Rule 210.d between tanks and smaller, portable vessels. It mirrors the definition of “container” from the U.S. Department of Transportation. Containers should already be labeled by their manufacturers, so it is not necessary to subject them to the labeling requirements of Rule 210.d. (1).

10. First Aid Treatment Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Rule 602. imposes different reporting requirements for incidents at oil and gas operations that require first aid treatment or medical treatment. Definitions for both terms were added. The definition for “first aid treatment” is taken from 29 C.F.R. § 1904.7(b)(5)(ii), which is the analogous federal regulatory definition adopted by the Occupational Safety and Health Administration.

11. Flowback Pits Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: The amendment clarifies that drilling pits include flowback pits and that such pits may be used to contain both fluids and solids produced during initial completion procedures.

12. Gathering Line Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: This term is used in multiple rules. The primary purpose of this addition is to clarify what the term means.

13. Green Completion Practices Basis: The statutory authority for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Rule 805., Odors and dust, requires operators to use green completion practices in certain circumstances. This addition makes clear to what that term refers.

14. LACT (“Lease Automated Custody Transfer” )

Basis: The statutory bases for this addition are sections 34-60-106(10) and 34-60-106(11)(a)(II), C.R.S.

Purpose: LACT is a common term in the oil and gas industry with a generally accepted definition. This addition reflects that definition and adds clarity for operators.

15. Material Safety Data Sheet (MSDS)

Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Rule 205. requires operators to maintain MSDSs. This definition makes clear to what that rule is referring.

16. Medical Treatment Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Rule 602. imposes different reporting requirements for incidents at oil and gas operations that require first aid treatment or medical treatment. Definitions for both terms were added. The definition for “medical treatment” is taken from 29 C.F.R. § § 1904.7(b)(5)(i) and 1904.46, which are federal regulations adopted by the Occupational Safety and Health Administration.

17. Minimize Adverse Impacts Basis: The statutory basis for this addition is section 34-60-103(5.5), C.R.S. Purpose: The purpose of this addition is to incorporate the definition of “minimize adverse impacts” from HB 07-1298.

18. Minimize Erosion Basis: The statutory bases for this addition are sections 34-60-106(11)(a)(II) and 34-60-128, C.R.S.

Purpose: The 1000-Series rules (reclamation rules) require operators to minimize erosion in certain circumstances. This definition makes clear what “minimize” is intended to mean. This clarification was necessary because erosion is a natural process that cannot be prevented.

19. Mitigation Basis: The statutory basis for this addition is section 34-60-128, C.R.S. Purpose: The 1200-Series of rules (wildlife rules) require operators to mitigate adverse impacts to wildlife resources. The definition makes clear what that term means, and confirms that it may involve, as appropriate, habitat enhancement, off-site habitat mitigation, or mitigation banking.

20. Oil and Gas Facility Basis: The statutory bases for this addition are sections 34-60-106(11)(a)(II) and 34-60-128(3) (d), C.R.S.

Purpose: Multiple rules refer to this term. This addition makes clear what this term means.

21. Oil and Gas Location Basis: The statutory bases for this addition are sections 34-60-106(11)(a)(II) and 34-60-128(3)(d), C.R.S.

Purpose: Many rules refer to this term. This addition makes it clear to what those rules are referring.

22. Ordinary High Water Line Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: This term is used in Rule 317B. This addition clarifies the method by which an operator can determine which rule provisions apply to its oil and gas location.

23. Public Water System Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: This term is used in Rule 317B. This definition was added to make clear what the term means. Appendix VI of these rules includes a list of Public Water Systems. In addition, the definition clarifies that the term does not include any “special irrigation district” as defined in Colorado Primary Drinking Water Regulations (5 C.C.R. 1003.1).

24. Reclamation Basis: The statutory bases for this addition are sections 34-60-106(11)(a)(II) and 34-60-128(3) (d), C.R.S.

Purpose: While the concept of reclamation is generally understood in the regulated community, the COGCC believes this addition is helpful to clarify to both surface owners and the regulated community the new standards required to be met under the rules.

25. Reference Area Basis: The statutory bases for this addition are sections 34-60-106(11)(a)(II) and 34-60-128(3) (d), C.R.S.

Purpose: Multiple rules use this term in connection with reclamation. This addition makes clear what the term means.

26. Restricted Surface Occupancy Area Basis: The statutory basis for this addition is section 34-60-128(3)(d), C.R.S. Purpose: Several rules, including Rule 1205., use this term in connection with wildlife protection. This addition makes it clear what the term means. Maps of restricted surface occupancy areas are attached as Appendix VII.

27. Sensitive Wildlife Habitat Basis: The statutory basis for this addition is section 34-60-128(3)(d), C.R.S. Purpose: Several rules, including Rule 1202., use this term in connection with wildlife protection. This addition makes clear what the term means. Maps of sensitive wildlife habitat are attached as Appendix VIII.

28. Solid Waste Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Multiple rules refer to solid waste. This addition makes clear to what those rules are referring.

29. Solid Waste Disposal Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Several rules, including Rules 907. and 1004., refer to solid waste disposal. This addition makes clear to what those rules are referring.

30. Stormwater Runoff Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Multiple rules, including Rule 1002., refer to stormwater runoff. This addition makes clear to what those rules are referring.

31. Surface Water Intake Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: The definition of surface water supply areas refers to this term, which has been added to help define the scope of Rule 317B.

32. Surface Water Supply Area Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Rules 206.b. and 317B., refer to this term. This addition defines the scope of Rule 317B.

33. Tank Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: While this term is generally understood in the regulated community, this addition will provide additional clarity.

34. Tier 1 Oil and Gas Location Basis: The statutory basis for this addition is section 34-60-106(11)(a)(II), C.R.S. Purpose: Rule 1002.f. refers to this term for purposes of stormwater management and thus necessitated its addition.

35. Trade Secret Basis: The statutory bases for this addition are sections 24-72-204(3)(a)(IV) and 34-60-106(11)(a) (II), C.R.S.

Purpose: Rule 205. refers to this term, and this definition clarifies what is meant by that reference.

36. Trade Secret Chemical Product Basis: The statutory bases for this addition are sections 24-72-204(3)(a)(IV) and 34-60-106(11) (a)(II), C.R.S.

Purpose: Rule 205. refers to this term, and this definition clarifies what is meant by that reference.

37. Wildlife Resources Basis: The statutory basis for this addition is section 34-60-128, C.R.S. Purpose: HB 07-1298 requires that the COGCC administer the Act so as to minimize adverse impacts to wildlife resources affected by oil and gas operations. This addition mirrors the statutory definition of that term.

Other Changes to the 100 Series The rules on file with the Colorado Secretary of State do not include the COGCC’s existing definitions for the terms “well site” , “wildcat (exploratory) well” , “zone of incorporation” , and “all other words” . These definitions were previously adopted by the Commission, and they are included with the new and amended rules to conform the rules on file with the Colorado Secretary of State to those on file with the COGCC. 200-Series General Rules Amendments to 200-Series The following rules were amended:

1. Rule 201., EFFECTIVE SCOPE OF RULES AND REGULATIONS Basis : The basis for the amendments to this rule pertaining to the Southern Ute Indian Tribe is Sec. 5, Public Law No. 98-290 (1984). Additional statutory bases for the amendments are sections 34-60-106(11)(a)(II) and 34-60-128, C.R.S.

Purpose : The primary purpose of these amendments was to clarify the scope of the rules. First, the rule emphasizes the legislative mandate to balance oil and gas development in a manner that protects public health, safety, and welfare, including the environment and wildlife resources. Second, the rule states the current law regarding operational conflict and local government regulation. Third, the rule clarifies the application of the rules to Indian trust lands and minerals and the Southern Ute Indian Tribe based upon existing law and current practice. Finally, the rule contains a severability clause.

2. Rule 205., ACCESS TO RECORDS Basis: The statutory bases for the amendments to this rule are sections 34-60-105(1) and 34- 60-106(11)(a)(II), C.R.S.

Purpose : The general purpose of Rule 205. is to ensure that operators maintain adequate records of their operations in Colorado. As part of its ongoing oversight of oil and gas activities in this state, the COGCC staff conducts investigations into alleged impacts to public health, safety, welfare, including the environment and wildlife, related to these oil and gas activities. To fully investigate alleged impacts thoroughly , COGCC staff must have access to information on chemicals and constituents contained in products and materials during certain oil and gas exploration and production activities. A readily available inventory of chemical products used or stored for use downhole will allow the COGCC staff to complete investigations into alleged impacts from oil and gas exploration and production activities more thoroughly and quickly. Under the former rules, it often would take several weeks or months for an operator to provide requested information, if at all.

Generally, amended Rule 205. requires oil and gas producers, operators and others in Colorado to maintain and make available for inspection certain records. The amendments adopted in this rulemaking require that oil and gas operators maintain certain information regarding chemicals used at a well site. The amendments also include definitions of certain terms to clarify these new requirements, including: Chemical(s), Chemical Inventory, Chemical Product, Material Safety Data Sheet (MSDS), Operator, Trade Secret, and Trade Secret Chemical Product. As amended, Rule 205. requires that beginning June 1, 2009 (on all lands), operators maintain a chemical inventory of all chemical products brought to a well site and used downhole or stored for use downhole during drilling, completion and workover operations, including fracture stimulation, as well as fuel stored at the well site. The inventory must include each chemical product for which an amount exceeding 500 pounds has been used or stored cumulatively during any quarterly reporting period. The Commission determined as a matter of policy that this threshold provides a reasonable balance between making information about chemical use available for the purposes described below and avoiding an unnecessary reporting burden for small quantities of materials that may be stored or used at oil and gas locations. The chemical inventories are required to be maintained at the operator’s local field office and updated quarterly throughout the life of an operation, to assure that the information contained in the inventory remains current.

The delayed effective date for this requirement will provide affected operators adequate time to establish systems and procedures for developing and maintaining chemical inventories. As an interim measure, amended Rule 205. requires that effective May 1, 2009 for federal lands and April 1, 2009 for all other land, operators shall maintain material safety data sheets (MSDSs) for any chemical products brought to a wellsite for use downhole during drilling, completion, and workover operations, including fracture stimulation. This provision is intended to refer to MSDSs prepared in accordance with 29 C.F.R. §1910.1200(g).

The purpose of the new chemical inventory requirements is to provide information that may be useful to COGCC staff, CDPHE , and medical professionals to investigate and address potential public health issues and environmental impacts from oil and gas operations. In addressing a spill or release from a site or a complaint from a potentially adversely impacted land owner, COGCC and CDPHE staff and county health or emergency officials need information regarding the chemicals involved in order to accurately focus sampling and analysis of potentially impacted media, as well as to determine appropriate remediation and response. Similarly, where individuals have been exposed to chemicals used at a well site, health professionals may need this information immediately to determine appropriate testing and treatment of those individuals.

The Commission heard substantial testimony regarding the legal and practical difficulties posed by the fact that the composition of many chemical products used in the oil and gas industry may be considered trade secrets. Because of the importance of protecting such information, the Commission adopted provisions that require the disclosure of information regarding the chemical constituents contained in a chemical product whose composition is a trade secret only under limited circumstances, and subject to limitations on the use of such information. In particular, such information is required to be disclosed to the Director (for use by COGCC and CDPHE staff or county health or emergency officials as needed) only where necessary to respond to a spill or release of a chemical product or a complaint by a potentially adversely affected landowner. The information is not to be disseminated further than necessary for response to the identified circumstances. The Commission determined that three business days is a reasonable deadline for the provision of chemical inventory information, except in a medical emergency, where the information must be provided immediately upon request, as discussed below. Similarly, provisions in Rule 205. provide chemical constituent information to health professionals where they have reason to believe that the information is necessary for diagnosis or treatment of an individual exposed to the chemicals. The health professional is generally required to sign a confidentiality agreement, although the rule provides that where necessary for emergency treatment, the information will be provided immediately based on an oral or written acknowledgement of confidentiality. A standardized confidentiality agreement will be developed by the Commission for this purpose with input from interested parties. This agreement will be known as COGCC Form 35, Confidentiality Agreement, and will be available on the COGCC web- site.

The requirement that health care professionals execute a confidentiality agreement is not intended to subject them to an enforcement proceeding by the COGCC or to impose substantive regulatory requirements on them. It merely sets forth a condition for their access to trade secret information, which is analogous to conditions that the Commission has imposed on other categories of persons, such as the designation of representatives by local governments under the 100-Series Rules, compliance with hearing procedures by parties under the 500-Series Rules, and satisfaction of onsite inspection requirements by surface owners under the Onsite Inspection Policy.

Where it is necessary that information regarding the chemical constituents in trade secret chemical products be disclosed, the Commission requires that such information be provided by the vendor or service provider in question, since those entities have more direct access to such information. However, the Commission included a provision stating that the oil and gas operator is ultimately responsible for providing the required information, in the event that the vendor or service provider fails to do so, unless the operator can demonstrate to the Director that it has made a good faith effort to obtain this information from the service provider or vendor and has not been able to do so. In such cases, a good faith effort will include providing evidence as to why it could not obtain this right via a contract agreement with the vendor or service provider and why this common practice couldn’t be employed The Commission has determined that this provision is necessary to assure that this rule serves its purpose of providing information needed for the protection of public health and the environment.

The Commission determined as a matter of policy that the Rule 205. provisions requiring the disclosure of information regarding trade secret chemical products in the limited circumstances identified strikes a reasonable and appropriate balance between oil and gas operators' interests in maintaining trade secrets and the public’s interest in the protection of public health and the environment.

The Commission appreciates representations of support from industry parties regarding the potential future need for studies of the possible public health impacts from oil and gas operations. The Commission also acknowledges industry's commitment to provide in a timely manner the chemical information necessary to complete useful studies once the COGCC staff, in consultation with the CDPHE, determines they are warranted. Relying on these representations, the Commission chose not to include rule language specifically addressing public health studies. Instead, the Commission expects that if such studies are initiated, industry will participate voluntarily to provide the information regarding chemical use that may be needed for those studies. In the event such voluntary efforts to provide information needed for studies are unsuccessful, the Commission will revisit this rule and consider revisions to the chemical inventory related requirements.

Beginning June 1, 2009, Rule 205.’s requirement that operators maintain a chemical inventory by well site will become effective on all lands.

3. Rule 206., REPORTS Basis: The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose: The purpose of Rule 206. is to provide oil and gas operators and the COGCC a tool for ensuring that operators pay regular attention to their compliance status with respect to certain COGCC rules. Specifically, the Compliance Checklist (Form 36) is intended to remind and assist the operator and COGCC in assuring compliance with the applicable regulatory requirements involving public health and environmental protection. This rule currently applies only within Garfield, Mesa, Rio Blanco and Gunnison Counties. Garfield, Mesa, and Rio Blanco Counties are anticipated to receive substantial additional oil and gas development activity, while Gunnison County affirmatively requested that the rule apply there. The Commission acknowledges that if use of the Compliance Checklist serves to reduce non-compliance situations, it may be expanded to other oil and gas development regions of the state, via a rulemaking pursuant to Rule 529. The Compliance Checklist includes twelve specific but simple questions that an informed on-site representative of the operator should be able to answer relatively easily. Based on past experience, the COGCC understands that when some oil and gas facilities fail to operate in compliance with on-site regulatory requirements on a consistent basis, this failure may have been the result of the lack of knowledge of the on-site operator, or the failure to adequately plan for and implement the requirements. For this reason, the COGCC believes that a Compliance Checklist should serve the primary purpose of ensuring that the operator takes an active approach to compliance with ongoing regulatory requirements. The COGCC expects operators to take the Compliance Checklist seriously and that it be fully updated annually and maintained at the operator’s local field office. Therefore, the failure to maintain an up-to-date Compliance Checklist at the operator’s local field office, where required, or including false information could result in a civil enforcement action. However, the Commission intends that such conduct would not result in a criminal enforcement action under section 34-60-121(2), C.R.S. The COGCC believes the rule allows a reasonable time for the initial completion of the Compliance Checklist, enabling the operator to perform the on-site evaluation and to take any necessary action to come into compliance prior to its completion and maintenance at the operator’s local field office. As a matter of policy, the Commission believes that the Compliance Checklist is a valuable tool to assist in assuring ongoing compliance with rules.

4. Rule 210., SIGNS AND MARKERS Basis: The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose: The amendments to this rule add the requirement that operators conspicuously label all of their tanks, from the time of initial drilling until final abandonment, with: the name of the operator; the operator’s emergency contact telephone number; the tank’s containment capacity; the tank’s contents; the tank’s National Fire Protection Association label; and the tank’s identification number from the U.S. Department of Transportation placard or shipping document. All tanks, regardless of construction date, must be labeled in accordance with this rule by September 1, 2009. In addition, this rule was amended to clarify how containers should be labeled. The addition of the definition of “container” was added to the rules to make clear what is considered a tank and what is considered a container. This amendment was necessary because, during the hearing, industry expressed concern that intermodal bulk containers and smaller vessels like drums would be considered tanks, which would be burdensome because such vessels are portable and frequently moved around.

This rule, as amended, is designed to provide additional information to emergency responders so they can quickly identify the hazards of a material(s) involved in an incident and protect themselves and the general public in the first phase of an emergency incident. This is consistent with the COGCC’s mandate to ensure that oil and gas operations are conducted in a manner that protects pubic health safety and welfare. Further, such a requirement is cost-effective because the financial burden on an operator to label its tanks in accordance with Rule 210. is minimal, particularly when compared to the benefit it can provide to enable first responders to effectively respond to an emergency incident.

5. Rule 215., GLOBAL POSITIONING SYSTEMS Basis: The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose : The purpose of this amendment is to ensure that more accurate results for locating oil and gas facilities are obtained when using global positioning systems. Additions to 200-Series The following rules were added:

1. Rule 201A, EFFECTIVE DATE OF AMENDMENTS Basis : The statutory bases for this addition are sections 34-60-106 and 24-4-103(5), C.R.S. Purpose: Unless otherwise specified, the general effective date of these rules is May 1, 2009 for federal land and April 1, 2009 for all other land. This delay is primarily in response to the desire of the COGCC to ensure a smooth transition to the new rules and to provide the regulated community with time to prepare appropriately for compliance with the rules. One representative of the regulated community suggested that the rules go in effect on July 1, 2009. Other affected stakeholders argued against this date, saying that Colorado’s environment and wildlife resources would be adversely affected each day the rules were not in effect. The Commission listened to both of these concerns and chose May 1, 2009 for federal land and April 1, 2009 for all other land as the general effective dates. These dates allow operators sufficient time to plan their oil and gas activities with the new rules in mind while being protective of the environment and wildlife resources. They also give the COGCC, CDPHE, and CDOW the ability to train employees properly regarding correct and efficient implementation of these rules. Making the rules generally effective on federal land one month after they become generally effective on other land is intended to provide additional time for the COGCC to work with federal officials to determine the relationship between the COGCC rules and federal regulations on such lands, and to update the existing Memorandum of Understanding between the COGCC and the Bureau of Land Management accordingly.

The Commission also reiterates that the amendments and new rules adopted on December 11, 2008 shall not apply to new or existing gas storage projects or operations that are subject to the jurisdiction of the Federal Energy Regulatory Commission, the safety aspects of projects that are regulated by the U.S. Department of Transportation, or midstream operations until the Commission conducts a further regulatory proceeding to address the manner in which such amendments and new rules shall apply to such projects and operations.

2. Rule 216., COMPREHENSIVE DRILLING PLANS Basis: The statutory basis for this rule is section 34-60-106(11)(a)(I)(A), C.R.S. In addition, the basis for this rule is HB 07-1298, as codified at section 34-60-128(3)(d)(II), C.R.S. Purpose: This rule provides an opportunity for operators, via Comprehensive Drilling Plans (CDPs), to identify reasonably foreseeable oil and gas activities in a defined geographic area and to facilitate early and collaborative planning with broad involvement about associated potential impacts and measures for minimizing them. The rule requirements are designed to offer flexibility and incentives for operators to take this broad approach to oil and gas development planning and permitting, effectively allowing the “bundling” of Form 2A requirements, presented in Rule 303. The Commission intends that if a CDP satisfies all of the informational and procedural requirements for a Form 2A, then no individual Form 2As will be required for wells covered by the CDP. The Commission also wishes to emphasize that satisfaction of the Form 2A informational and procedural requirements by a CDP will need to include measures that are substantially equivalent to those included in the public notice and comment requirements as provided in Rule 305., requirements to consult with CDPHE and DOW, where applicable, as provided in Rule 306., and the basic Form 2A informational requirements listed in Rule 303. The Commission also intends the rule to allow operators to develop CDPs that are more narrowly focused, effectively allowing the “bundling” of consultation requirements presented in Rule 306. For example and with respect to drinking water protection, an operator may want to address in a CDP only variances from Rule 317B drinking water provisions. In this case, the CDP would focus only on how the operator plans to mitigate and protect drinking water resources and not necessarily involve other protected resources, such as wildlife. Such a CDP would also involve consultation with CDPHE and thus eliminate the need for consultation with CDPHE regarding drinking water relative to the identified oil and gas wells at any future date, unless the operator wishes to alter the terms of the CDP. As such, subsequent satisfaction of Form 2A procedural and public notice and comment requirements could be tailored to fit the contents of the CDP. However, the Commission wishes to emphasize that the CDP can not “shield” operators from Form 2A and associated public notice and comment, informational and other applicable requirements not otherwise addressed in the CDP. In other words, the operator may develop a draft CDP however it chooses, but the information that is included or not included will have a significant bearing on what kind of procedural benefits result from the CDP. A narrowly focused CDP will result in fewer procedural benefits and thus a broader Form 2A process. This underscores the importance for operators to discuss with the COGCC, CDPHE, and CDOW their plans and expectations for a CDP before initiating work on it. Thus, the Commission intends CDPs to be a flexible planning and permitting tool, which operators can tailor to their needs and circumstances. In this way, the Commission seeks to encourage landscape level planning and regulatory review as contemplated by HB 07-1298 and supported by a number of parties. This should help to better address cumulative effects, promote efficiently, and facilitate more win-win situations. It is the opposite of a one-size-fits-all approach. The Commission also recognizes that CDPs by their very nature address more comprehensive oil and gas activity and associated impacts. Furthermore, activities contemplated within the CDP are likely to occur over a potentially longer period of time and involve greater up-front planning and negotiations. In view of this, the Commission believes it is appropriate that the CDP term be extended beyond that for Form 2As; from three to six years, and that the Commission itself consider CDPs through its hearing agenda.

The Commission wishes to clarify how the provision relating to confidentiality in Rule 216.d.(6) works. The rule says the Director will post accepted CDPs on the COGCC web-site, subject to any confidential or proprietary information belonging to the operator being withheld. This means that the Director will not post information the operator designates as confidential. However, if any person makes a Colorado Open Records Act (“CORA” ), sections 24-72-100.1 et seq , C.R.S., request for the information, labeling a document “confidential” does not end the inquiry as to whether it is exempt from disclosure. If the COGCC receives a CORA request for information labeled “confidential” , the COGCC staff, as custodian of the records, will independently determine whether such information is exempt from disclosure pursuant to CORA. If the COGCC staff determines a document is exempt from disclosure pursuant to CORA, it will keep such information confidential to the maximum extent allowed by law. The Commission intends that for purposes of mapping riparian areas when submitting information for a CDP, an operator need only make reasonable good faith effort to identify such areas and they may rely on any appropriate and credible source of information on riparian areas in doing so. The Commission also intends that if a CDP is approved before Rule 216 becomes effective, then such CDP will be treated the same as CDPs approved after Rule 216 becomes effective. The Commission understands that the staff is already discussing CDPs with several operators in a manner consistent with the Final Draft Rules and encourages this effort. If a CDP is finished before the rule amendments become effective on May 1, 2009 on federal land or April 1, 2009 on other land, it will be treated the same as a CDP adopted after these dates. 300-Series Drilling, Development, Producing and Abandonment Amendments to the 300-Series The following rules were amended:

1. Rule 302., COGCC FORM 1. REGISTRATION FOR OIL AND GAS OPERATIONS Basis : The statutory basis for this Rule is section 34-60-106(11)(a)(II), C.R.S. Purpose: This amendment pertains to the portion of COGCC Form 1A, Designation of Agent, which deals with the designation of an agent for the operator. The purpose of this amendment is to clarify rule language and to make it clear that when an individual signs this form, such individual is explicitly identifying himself or herself as someone that is authorized by the operator to act on behalf of the operator. The previous rule language stated that “any party may act on or for the behalf of the operator” if such party filed this form. The amended language clarifies the intent of the original language by stating that the individual that signs a designation of agent form must be approved by the operator to do so.

2. Rule 303., REQUIREMENTS FOR FORM 2, APPLICATION FOR PERMIT-TO-DRILL, DEEPEN, RE- ENTER, OR RECOMPLETE, AND OPERATE; FORM 2A, OIL AND GAS LOCATION ASSESSMENT Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II) and 34-60- 128( 3 )(d), C.R.S.

Purpose : Rule 303. was substantially reorganized and revised to reflect significant changes desired by the COGCC and mandated by HBs 07-1298 and 07-1341 . The minor, conforming changes to this rule are not individually addressed.

a. Rule 303.a – Form 2. Application for Permit-to-Drill, Deepen, Re-Enter, or Recomplete, and Operate Rule 303.a.(1) was amended to require that an Application for Permit-to-Drill, Form 2 must be accompanied by an Oil and Gas Location Assessment, Form 2A. This existing requirement was reworded and moved to Rule 303.a.(1) from Rule 303.d.(1). In addition, Rule 303.a.(2) previously stated that the Director’s approval of an APD is considered final agency action for purposes of judicial review. This provision was moved to Rule 305.d.(3) and clarified to state that the issuance of an approved Form 2 or Form 2A by the Director is deemed the final decision of the Commission and subject to judicial review if it is not suspended by a timely request for a Commission hearing submitted by a party with standing.

b. Rule 303.c – Form 2. Application for Permit-to-Drill, Deepen, Re-Enter, or Recomplete and Operate Prior to amendment, Rule 303.c. required that the Form 2 include: a well location plat or addendum depicting visible improvements within 200 feet of a wellhead or 400 feet of a wellhead in high density areas; a description of surface uses within those distances; and a U.S.G.S. topographic map depicting a radius of at least three miles around the well and showing access from one or more public roads. These requirements have been moved from Form 2 to Form 2A and modified to include depictions of visible improvements and descriptions of surface uses within 400 feet of the wellhead in all areas and eliminate the three mile radius requirement for the U.S.G.S. topographic map. As modified, these requirements are now addressed under Rule 303.d. The Commission intends that subsurface issues will be primarily addressed through Form 2 while surface disturbance will be primarily addressed through Form 2A.

c. Rule 303.d. – Form 2A. Oil and Gas Location Assessment As amended, Rule 303.d.(1) requires the submittal of a Form 2A for any “new oil and gas location,” and defines that term to mean surface disturbance at a previously disturbed site or surface disturbance that modifies or expands a location existing on the general effective date of the amendments. As amended, Rule 303.d.(2) will exempt from this requirement: surface disturbance occurring within the originally disturbed area at an existing oil and gas facility unless it involves drilling a new well or constructing a drilling or production pit; locations covered by certain CDPs; gathering lines; seismic operations; pipelines for oil, gas, or water; and roads. These rules ensure that a Form 2A is submitted for those oil and gas developments that are most likely to adversely affect public health, safety, and welfare, including the environment and wildlife resources. This balances environmental and wildlife protection with regulatory efficiency as the General Assembly directed.

1. The Commission anticipates that a Form 2A will be submitted for a location concurrent with the submittal of the first Form 2 for a well at that location. Subsequent Form 2s for additional wells at that location may reference the Form 2A. This should promote efficiency for the COGCC, permit applicants, and other regulatory participants by providing for one review of surface disturbance associated with a new location rather than repetitive reviews of such disturbance with each application for a permit to drill an individual well there.

   As amended, Rule 303.d.(3) specifies the information required in a Form 2A. Some of this information was required under the prior version of Rule 303.d. Other information was previously required under Rule 303.a., and has been moved from Form 2 to Form 2A as discussed above. Other information is new, such as: a list of major equipment components used in conjunction with drilling and operating the wells and a description of any pipelines for oil, gas, or water; information regarding water resources and reclamation; and information on the surface owner and any surface use agreement. Still other information is not required under all circumstances, but only where particular circumstances exist, such as: where the location is sited on a steep slope, is within sensitive wildlife habitat or a restricted occupancy area, or is within a public drinking water buffer zone established to protect public drinking water; where the location involves multiple wells on a single pad; where the applicant proposes BMPs or requests a variance; or where the location is covered by a CDP. Thus, the Form 2A requirements are tailored to the individual circumstances of the location, do not reflect a one-size-fits-all approach, and should generally require more information in the Piceance Basin than in other areas of the state. In the interest of efficiency, amended Rule 303.d.(3) also specifies that if the required information is included in certain federal documentation, then the applicant may attach such documentation to the Form 2A. The Commission intends that for purposes of mapping riparian areas when submitting information for a Form 2A, an operator need only make reasonable good faith effort to identify such areas and they may rely on any appropriate and credible source of information on riparian areas in doing so.

   The Commission believes that the additional information in Form 2A will help the COGCC to better evaluate the potential for proposed oil and gas locations to adversely impact public health, safety, and welfare, including the environment and wildlife resources, and to develop special conditions where appropriate to minimize such impacts and ensure appropriate reclamation as directed by the General Assembly, while ensuring a timely and efficient process. This additional information will also help the COGCC to monitor the extent of surface disturbance and the number and location of certain equipment components, which should improve the COGCC’s ability to assess the cumulative impacts associated with oil and gas development. These information requirements are substantially fewer than the initial Form 34 concept that was included in the COGCC staff’s November 2007 pre-draft proposal, and they have also been revised from the March 2008 draft rules. After considering extensive testimony on this subject, the Commission believes that these information requirements are reasonable and appropriate under the current circumstances.

   As amended, Rule 303.d.(4) requires approval of the Form 2A prior to approval of a Form 2 or other permit under the following circumstances: where the proposed location will disturb more than one acre and is within Garfield, Mesa, Rio Blanco, or Gunnison Counties; where consultation with the CDPHE or CDOW occurs; or where an ancillary facility would serve multiple wells and is not otherwise approved by the COGCC. In other circumstances, Form 2A is merely an informational report. Garfield, Mesa, and Rio Blanco Counties were the site of approximately half of the Form 2s issued in 2007, and they are currently the location of approximately three-quarters of the drilling rigs operating in Colorado, while Gunnison County affirmatively requested that the Form 2A approval requirement apply there. In addition, these counties all pose more challenging public health and welfare, environmental, and wildlife resource issues. Therefore, the Commission concluded that requiring approval of Form 2As in these counties will help to ensure that adverse impacts to the environment and wildlife resources are minimized. The Commission also concluded that requiring Form 2A approval where consultation occurs with the CDPHE or CDOW and where large ancillary facilities would not otherwise be subject to COGCC approval will likewise help to ensure that the environment and wildlife resources receive appropriate protection under those circumstances. The Commission considered extensive staff and party testimony and public comment in deciding to adopt these amendments. Some participants requested much more extensive and restrictive regulatory changes, while others urged far fewer and less restrictive changes. The amendments reflect the Commission’s policy decision, which seeks to balance the need for additional consideration and protection of public health and welfare, the environment, and wildlife resources with the need to maintain a timely and efficient permitting process as directed by the General Assembly.

d. Rule 303.e. - Processing Time for Approvals As amended, Rule 303.e. sets forth the timelines by which applicants can expect a decision on a Form 2 or, where approval is required under Rule 303.d.(4), a Form 2A. It requires the Director to make such a decision within 30 days if the proposed location is covered by a CDP and no variance is requested. It also provides that whether or not the location is covered by a CDP the applicant may request an expedited hearing before the Commission if the Director has not made a decision within 75 days. This expedited hearing, however, will not occur before proper notice is given under the Act. See C.R.S. § 34-60-108.

1. The shorter processing period for Form 2s and Form 2As covered by a CDP is intended to create an incentive for the development of such plans and thereby promote landscape level planning. The Commission believes that expedited processing of such Forms is feasible because the CDP should identify actions and conditions to minimize adverse impacts to the environment and wildlife resources. The ability to request an expedited hearing if a decision on a Form 2 or Form 2A is not made within 75 days is intended to ensure that the approval process remains timely and efficient as directed by the General Assembly and to address industry concerns that applications will routinely require many months to process. It is also intended to make the timing of Commission decisions more predictable for industry, which will assist in industry’s business planning. The Commission understands that the current permitting process has recently averaged more than 60 days to complete. It believes that this average can and should be reduced consistent with COGCC staffing levels and the number of applications that are filed. Although the Commission has provided for a hearing if the process extends beyond 75 days, the Commission intends that a 75 day process would be the exception and not the rule. The Commission encourages the staff to work to reduce the current application backlog as additional staff are added in 2009.

e. Rule 303.g. – Revisions to Form 2 or Form 2A As amended, Rule 303.g. authorizes the Director to request supplemental information when non-substantive revisions are made by an operator to an approved Form 2 or Form 2A. Prior to this amendment, the authority of the Director to request such information was unclear and created potential uncertainty.

f. Rule 303.h. – Incomplete Applications As amended, Rule 303.h. states that incomplete Form 2s and Form 2As will not be reviewed. As noted above, the COGCC currently receives thousands of permit applications a year. Applicants have the responsibility to comply with all required regulations, and the COGCC should not use its limited resources to evaluate an incomplete application. This amendment gives operators notice that incomplete applications will not be considered, and it thereby creates an incentive for operators to ensure the applications are complete before they are submitted. Rule 303.h. was also amended to provide that where a Form 2 or Form 2A is covered by a CDP the COGCC will shorten its completeness review period from ten days to three business days. This is intended to create an additional incentive for operators to develop CDPs and thereby to further promote landscape level planning.

g. Rule 303.i. – Information Requests After Completeness Determination Rule 303.i. is a new provision that clarifies the Director’s authority to ask the operator for additional information that is needed to review a Form 2 or Form 2A, notwithstanding that the Form was determined to be technically complete. This amendment simply codifies current COGCC practice and is not intended to change that practice. The amendment also states that such a request will not affect the applicant’s right to request a hearing before the Commission if the Director does not make a decision within 75 days after the Form 2 or Form 2A was originally determined to be complete under Rule 303.h.

h. Rule 303.j. – Permit Expiration As amended, Rule 303.j. retains the current one year term for approved Forms 2 and creates a new three year term for approved Forms 2A. The Commission retained the one year term for Forms 2 to ensure that the special conditions remain current where drilling operations are not commenced within a year. In addition, the Act promotes the development of oil and gas resources, and the Commission wants to deter operators from sitting on their rights and not developing the minerals as authorized. The Commission created a three year term for Forms 2A to provide operators with additional time to develop oil and gas locations.

i. Rule 303.m. - Special Circumstances for Withholding Approval of Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A As amended, Rule 303.m. authorizes the Director to withhold approval of a Form 2A as well as a Form 2 under certain circumstances and expands those circumstances to include a material threat to wildlife resources. In addition, the rule previously required the Director to withhold such approval when a request for a hearing on the permit is made by a local governmental designee and stated that such a hearing would be expedited. These provisions have been deleted as unnecessary because under amended Rule 305.d. the Director must suspend the approval when a timely hearing request is made by the local government designee. Because the approval can now be suspended, there is no longer a need to withhold it under these circumstances, and the timing of the hearing has been addressed in the 500-Series consistent with other hearings on a Form 2 or Form 2A.

3. Rule 304., FINANCIAL ASSURANCE REQUIREMENTS Basis : The statutory bases for this amendment are sections 34-60- 106(11)(a)(I)(A) and 34-60- 106(13), C.R.S.

Purpose: The amendment to this rule expands the authority of the Director and enables him to withhold approval of a Form 2A if an operator’s existing wells are not in compliance with the 700- Series rules (Financial Assurance). This is appropriate because an operator should not be able to disturb the surface of land for its operations if it cannot ensure that proper reclamation will occur.

4. Rule 305., NOTICE, COMMENT, APPROVAL (formerly NOTICES OF OIL AND GAS OPERATIONS) Basis: The statutory bases for this rule are sections 34-60-106(11)(a)(II) and 34-60-106(14), C.R.S.

Purpose : Current COGCC rules provide individualized notice of Form 2 applications only to the local government designee. Although the COGCC notifies the public of such applications by posting a summary notice on the COGCC web-site, anyone wishing to review an application must do so at the COGCC offices. Surface owners receive notice before certain operations are undertaken, but not of permit applications. Amended Rule 305. significantly enhances the transparency of the permitting process by providing that the entire Form 2A will be posted on the COGCC web-site, by extending individualized notice to the CDPHE, CDOW, surface owners, and the owners of surface property within 500 feet of the location, and by providing at least a 20 day period for receipt and consideration public comment. These and other changes summarized below are intended to result in permitting decisions that are better informed and more protective of public health, safety, and welfare, including the environment and wildlife resources. Amended Rule 305. directs operators to provide the surface owner and the owners of surface property within 500 feet of the proposed oil and gas location with a copy of the Form 2A and limited information about major equipment components, visible surface improvements, and road access. Operators must also provide the surface owner with certain additional information concerning the owner’s rights under COGCC rules and policies. The Commission heard testimony that many local governments provide or require notice to adjacent landowners of land use applications. It determined that requiring notice to the surface owner and the owners of surface property within 500 feet is appropriate as a matter of policy because those individuals are the most directly affected by the proposed activity and may therefore have information on issues regarding public health, safety, and welfare, including the environment and wildlife resources. The Commission emphasizes that the complete Form 2A need not be used for this purpose and that operators may rely on local tax records to identify the recipients of the notice. In addition, the requirement to provide notice to the owners of surface property within 500 feet will not apply to areas covered by Rules 318A or 318B. Because surface locations in those areas are identified in detail in the rules, and because those rules were the subject of extensive public discussion when they were adopted, nearby landowners are essentially on notice of the likelihood of oil and gas operations already. While the Commission appreciates that requiring additional notice to surface owners and the owners of surface property within 500 feet will impose certain additional costs on operators, it believes that such costs are reasonable under the circumstances. Amended Rule 305 also directs that a Form 2A will be posted on the COGCC web-site once it is determined to be complete, and that the COGCC will provide concurrent electronic notice of such posting to the relevant local governmental designee and, where consultation is triggered under Rule 306., to the CDPHE and CDOW. Where the proposed oil and gas location is covered by an accepted Comprehensive Drilling Plan, the web-site posting will include directions for the review of that Plan. Posting the Form 2A itself rather than a summary notice of the application will make it easier for interested members of the public to review the Form and obtain information on the proposed development. Providing concurrent electronic notice of the posting to the local government designee, CDPHE, and CDOW will facilitate their ability to timely consult. The Commission wishes to emphasize that to avail itself of these and many other rights under the rules, a local government must provide the COGCC with a written designation identifying its local government designee.

The web-site posting of the Form 2A will initiate a 20-day period during which the COGCC will accept and post any comments it receives on the Form 2A or any associated Form 2. Although the COGCC will consider such comments, it does not anticipate responding to them. This 20-day comment period may be extended to 30 days upon a written request received during the 20-day period from the local governmental designee, the CDPHE, the CDOW, or a landowner who receives notice under the amended rule as described above. This 20-day comment period represents a balance between several competing interests and considerations. Some parties urged a longer comment period such as 30 days or more, while others urged a shorter period or no comment period at all. The 20-day period represents a policy decision by the Commission that is intended to strike an appropriate balance between transparency and expediency. The Commission believes that a 20-day comment period responds to legislative direction to provide a timely and efficient procedure for the review of APDs.

Upon the conclusion of the comment period and, where applicable, consultation with the CDPHE or CDOW, the Director may attach technically feasible and economically practicable conditions of approval to the Form 2A or Form 2. The COGCC will promptly provide notice of the Director’s decision on the Form 2 or Form 2A to parties with standing to request a hearing under Rule 503. The Director’s approval of a Form 2 or Form 2A will be suspended if a party with standing under Rule 503. requests a hearing within ten days after the Director’s decision is issued. In such event, the Director will set the matter for an expedited hearing, consistent with the notice requirements of the Act. This ten-day period is intended to allow parties with standing to review the Director’s decision and decide whether to exercise their hearing rights, while still allowing for a timely and efficient procedure. If no party with standing to request a hearing does so within ten days after the decision is issued, then the permit will issue as proposed by the Director and the Director’s decision is deemed a final decision of the Commission, subject to judicial appeal. If the decision were immediately deemed final, then this could preclude parties with standing from exercising their hearing rights under Rule 503.

Amended Rule 305. retains provisions from the previous rules for providing notices of drilling activities (called the “advance notice” in the amended rules), appointing agents, notifying tenants, and providing surface owners with notices of subsequent well operations, drilling during irrigation seasons, and commencement of final reclamation. The amended Rule adds to the waiver section a provision stating that surface owners and their successors in interest may rescind that waiver to the extent allowed under applicable law. Finally, the amended Rule directs an operator to post a sign at the intersection of the lease road and the public road providing access to the well site at least 30 days before commencement of drilling. This represents a policy decision that refines the previous requirement that notice be posted “on or near the proposed drillsite” and will ensure that those in the vicinity who do not receive individual notice are notified of upcoming drilling activities. Amended Rule 305. reflects a series of policy decisions by the Commission based on extensive input from the staff, parties, and public. After considering this input, the Commission concluded that the amendments will increase transparency and improve decision making while still ensuring that the approval process remains timely and efficient. The Commission also believes that facilitating input from the local governmental designee, the CDPHE, the CDOW, the surface owner, the owners of surface land within 500 feet, and the public will help ensure protection of public health, safety, and welfare, including the environment and wildlife resources, by helping to identify potential issues, impacts, or conflicts early in the permitting process. By notifying these persons and the general public of an application, and by soliciting comment from them before a decision is made, the COGCC may learn of issues or problems that would not otherwise be considered. The notice and comment provisions of Rule 305. should thus result in permitting decisions that are better informed and more protective of important state resources.

5. Rule 306., CONSULTATION Note: Rule 306. was reorganized and revised to reflect significant changes authorized and mandated by HBs 07-1298 and 07-1341.

Basis: The statutory bases for this rule are sections 34-60-106(1)(f), 34-60-106(11)(a)(II) and 34- 60-128(2)(d), C.R.S.

Purpose : Rule 306. reflects the Commission’s response to the General Assembly’s directive that the CDOW and CDPHE have a consultative role in certain aspects of COGCC decision- making and the Commission’s belief that such consultation will lead to better informed decisions. The Commission heard extensive testimony regarding the nature of, participants in, and timeframe for such consultation and arrived at what it believes is a balanced, effective and fair approach to implementing the consultation directive. The cornerstone of the Commission’s policy approach toward consultation has two key elements: (1) to allow CDOW to consult on oil and gas development in sensitive wildlife habitat (which is primarily located in western Colorado) in order to minimize adverse impacts to Colorado’s wildlife resources; and (2) to allow CDPHE to consult in more limited circumstances to ensure that public health, safety, welfare and the environment are protected. The Commission’s policy approach also recognizes the key role the operator and surface owner have in oil and gas development decisions, while emphasizing the need for timely and efficient decision-making and the importance of developing oil and gas resources. As amended, Rule 306.a. describes the consultation process between the operator and the surface owner or the surface owner’s agent. This provision restates and clarifies language from the existing rule, which was previously set forth in the introductory paragraph and subsections 306.a.(1) and (2). Amended Rule 306.b. describes the consultation process with local governments, and it restates and clarifies existing Rule 306.a.(3). Amended Rules 306.e. and 306.f. address final reclamation consultation and consultation with tenants, and they restate and clarify existing Rules 306.c. and 306.d.

Amended Rule 306.c. adds a new consultation process with the CDOW. Such consultation will occur where: (1) consultation is specifically required by the 1200 Series Rules (i.e., where the location would occur in sensitive wildlife habitat); (2) the operator seeks a variance from a requirement under the 1200 Series Rules (e.g., where a variance is sought from the restricted surface occupancy area limitations); (3) the CDOW requests consultation because the location would occur in known occurrence or habitat of a federally threatened or endangered species); or (4) the operator seeks to increase well density to more than one well per 40 acres or the Commission develops a basin-wide order involving wildlife. Amended Rule 306.d. adds a similar new consultation process with the CDPHE. The circumstances where consultation with the CDPHE occurs are more limited because the CDPHE already administers numerous rules and regulations for protecting public health, safety, welfare, and the environment. Therefore, consultation with the CDPHE will occur only where: (1) the local government designee requests participation by the CDPHE because of health, safety, welfare, or environmental concerns; (2) the operator seeks a variance from a one of certain rules intended to protect public health, safety, welfare, or the environment (e.g., rules pertaining to public water system protection, underground disposal of water, setback requirements in high density areas, coalbed methane wells, odors and dust, E&P waste management, and stormwater management); or (3) the operator seeks to increase well density to more than one well per 40 acres or the Commission develops a basin-wide order involving public health, safety, welfare, or the environment.

In amending Rules 306.c. and 306.d, the Commission intended to ensure that the permitting process remains timely and efficient. Therefore, the amendments establish a 40-day time period for consultation by the CDOW and CDPHE. This 40-day period will begin concurrent with the start of the public comment period, and if consultation does not occur within such 40-day period then the consultation requirement is waived. Therefore, consultation with the CDOW and CDPHE will occur simultaneously with the public comment period and the COGCC staff’s review of the Form 2 and Form 2A, and it should therefore not significantly extend the decision-making period. The Commission also encourages and expects that for particular applications the CDOW and CDPHE may complete their consultations in less than 40 days.

In amending Rules 306.c. and 306.d., the Commission also recognized the importance of predictability for operators. To this end, the amendments set forth standards that the CDOW and CDPHE will use in making recommendations regarding conditions of approval and variance requests. The amendments also provide standards that the Director will use in considering such recommendations. The Commission intends that the Director will give due consideration to the recommendations of CDOW and CDPHE, but that the Director will remain responsible for deciding whether to approve permits or variances and whether to impose special conditions on such approvals.

These amendments reflect substantial input from the staff, parties, and public on these issues. After considering all of the testimony, comment, and other evidence, the Commission determined as a matter of policy that these amendments strike an appropriate balance between protecting public health, safety, and welfare, including the environment and wildlife resources, and ensuring that the approval process remains timely, efficient, and predicable. It also believes that the amendments will improve COGCC decision making by providing the Director with expert input from the CDOW and CDPHE regarding those applications that raise the most significant issues regarding public health, the environment, and wildlife resources.

6. Rule 312., COGCC Form 10. CERTIFICATE OF CLEARANCE AND/OR CHANGE OF OPERATOR Basis: The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose: The amendment to this rule clarifies the circumstances under which an operator must file a Form 10 with the addition of Rule 312.i., which requires a completed Form 10 for any change of operator for all oil and gas facilities except those that are covered by Form 12 (i.e., gas gathering systems, gas-processing plants, and gas storage facilities).

7. Rule 317., GENERAL DRILLING RULES Basis: The statutory basis for this rule are sections 34-60-106(1)(f) and 34-60-106(11)(a)(II), C.R.S.

Purpose: The purpose of this amendment is to ensure that the production casing is properly in place, ensuring that the public safety is protected. This practice is technically feasible and cost- effective.

8. Rule 318A., GREATER WATTENBERG AREA SPECIAL WELL LOCATION, SPACING AND UNIT DESIGNATION RULE Basis: The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : This rule was amended by the addition of section 318A.k., which clarifies that the new notice provisions of Rule 305.e. that pertain to the owners of surface property within 500 feet of the proposed oil and gas location do not apply to oil and gas operations that are regulated by Rule 318A. Those operations have their own location and notice requirements, and are in an area with a history of oil and gas development.

9. Rule 318B., YUMA/PHILLIPS COUNTY SPECIAL WELL LOCATION RULE Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : This rule was amended by the addition of section 318B. g ., which clarifies that the new notice provisions of Rule 305.e. that pertain to the owners of surface property within 500 feet of the proposed oil and gas location do not apply to oil and gas operations that are regulated by Rule 318B. Those locations, too, have their own location requirements, and they, too, are in an area with a history of oil and gas development.

10. Rule 319., ABANDONMENT Basis : The statutory basis for this Rule is section 34-60-106(11)(a)(II). Purpose: This rule was amended to clarify subsection b. That subsection deals with shutting-in and temporarily abandoning wells. Shut-in wells are wells that are capable of production but have been voluntarily shut-in by an operator. Abandoned wells are wells that are not capable of production and pose a potential threat to public health, safety, and welfare. Minor changes were made to the subsection to clarify several requirements and correct a cross reference. 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).

11. Rule 324A., POLLUTION Basis: The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose : The amendments to this rule follow the language of HBs 07-1298 and 07-1341. In addition, the amendments clarify that operators must follow all applicable state and federal laws regarding pollution while conducting oil and gas operations. The Commission wishes to emphasize that this rule continues to require that operators take precautions to prevent significant adverse impacts to air, water, soil, or biological resources to the extent necessary to protect public health, safety and welfare, and to prevent the unauthorized discharge of disposal of oil, gas, exploration and production waste, chemical substances, trash, discarded equipment or other oil field waste. Therefore, if the Commission or Director has reasonable cause to believe an operator is violating this rule, remedial action may be taken.

12. Rule 324B., EXEMPT AQUIFERS Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: The amendment to this rule states that CDPHE must be notified when the COGCC is requested to designate an aquifer or a portion thereof as an exempted aquifer. This is appropriate because CDPHE has expertise to provide input (if it so chooses) on aquifer exemption classification.

13. Rule 333., SEISMIC OPERATIONS Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II) , C.R.S . Purpose: Prior to the amendment, Rule 333. referred to an “occupied building” . The Rules do not define “occupied building” . Therefore, the rule was amended to refer to a “building unit” , which is a defined term in the COGCC rules.

Additions to the 300-Series The following rules were added:

1. Rule 317B., PUBLIC WATER SYSTEM PROTECTIONS Basis: The statutory bases for this rule are sections 34-60-102 and 34-60-106, C.R.S. Purpose: In adopting this new rule, the Commission’s primary objective was to minimize the potential for accidental contamination, including from sedimentation or chemicals, of public drinking water supplies due to oil and gas operations in Colorado. The first opportunity for protecting drinking water supplies is to protect the source water itself. As such, the Commission decided that, as a matter of policy, adequate protection of public drinking water supplies requires the creation of protection zones combined with performance requirements applicable within certain distances of classified water supply segments. To clarify and support this policy approach, the Commission established several new definitions, including those for: Classified Water Supply Segment, Ordinary High-Water Line, Public Water System, Surface Water Intake, Surface Water Supply Area, Drilling Completion Production and Storage (DCPS) Operations, Non-Exempt Linear Feature, Existing Oil and Gas Location, New Oil and Gas Location and New Surface Disturbance. This policy approach was supported by a number of parties and public comments. The approach to protecting public drinking water reflected in the rules adopted by the Commission includes establishment of an “Internal Buffer Zone” , applicable to Drilling, Completion, Production, and Storage (“DCPS” ) Operations located within 300 feet of a Classified Water Supply Segment. This most protective zone serves essentially as a drilling exclusion zone or “setback” , unless an operator satisfies the stated variance criteria, which include offering substantially equivalent protection of drinking water quality (see below). The premise for establishing this zone is that a significant release in these areas would likely contaminate surface water used as drinking water source quickly, thereby not allowing the public water system, the oil and gas operator, nor the COGCC enough time to respond effectively to protect the public water system. As part of these new drinking water protection provisions, the Commission also decided that enhanced drilling and production requirements should apply in areas beyond the Internal Buffer Zone and up to ½ mile from the Classified Water Supply Segment. To this end, the Commission established Intermediate and External Buffer Zones and associated operating requirements applicable to DCPS Operations.

The definition of Surface Water Supply Area was originally proposed to include groundwater under the influence of surface water as well as seeps and springs to extend the protections of Rule 317B to those particular waters that serve as sources of public water systems. At the request of COGCC and CDPHE staff, the Commission has deleted the reference to these waters from the definition of Surface Water Supply Area because of the identification of issues that relate to the physical differences between surface water segments and groundwater under the influence of surface water, and the need to ensure that the protections afforded all public water systems under Rule 317B are consistent. It is the Commission’s intent that public water systems that utilize groundwater under the influence of surface water, seeps, and springs enjoy the protections under Rule 317B, therefore the Commission expects staff to report back to the Commission by the Fall of 2009 with its recommendations regarding the appropriate means to protect these public water systems.

With respect to roads, gathering lines and pipelines, the intent of Rule 317B is to exempt them from the rule, except for most of those within the Internal Buffer Zone. Specifically, the rule allows those roads, gathering lines or pipelines that are necessary to cross a stream or connect or access a well or gathering line to be located within the Internal Buffer Zone. The operator will have to confirm on its Form 2A that the feature will be located within the Internal Buffer Zone and that it is necessary to cross a stream or connect or access a well or gathering line. For purposes of this rule, such a feature cannot be considered necessary simply because it is the most proximate and least expensive method for gaining access or moving material through a pipeline. Instead, the operator must factor in other reasonably proximate options for placing these linear features. Conversely the Commission intends that roads, gathering lines or pipelines within the internal buffer zone which are not necessary to cross a stream or connect or access a well or gathering line not be allowed, unless a variance is granted. The Commission further intends that staff will grant a variance request for this purpose only if the operator demonstrates that locating the feature outside the Internal Buffer Zone would pose a greater risk to public health, safety, or welfare, including the environment and wildlife resources. Finally, the Commission expressly intends that this rule apply only to roads, gathering lines or pipelines that did not exist on May 1, 2009 for federal lands and April 1, 2009 for all other lands. The Commission recognizes that, as a matter of policy, there is a clear need to balance protection of drinking water with development of energy resources. Therefore, the Commission included allowances for oil and gas operations that existed prior to the rulemaking that are within the Internal Buffer Zone to remain in place and to expand these operations under certain conditions. Again, recognizing the need for balance, the Commission established rule provisions for those situations where a variance can be requested for placement of new oil and gas operations in the Internal Buffer Zone.

The Commission heard testimony from representatives of the oil and gas industry that these rules were unnecessary and that there were no documented incidents of releases from oil and gas facilities that had adversely impacted public water systems. Testimony, however, was also provided by CDPHE staff recounting recent spills that had affected surface water. In one case, a private groundwater well that was under the influence of surface water had been contaminated by oil and gas operations. Given these occurrences and the rapid pace of oil and gas development in Colorado, the Commission concluded that it would be imprudent not to establish rules for protecting public drinking water supplies. The Commission believes Rule 317B strikes a balance between reducing the possibility of a serious impact to a public water system from an oil and gas operation before such an accident occurs and allowing development of oil and gas resources to continue.

In addition, the Commission heard testimony from industry representatives that advocated that the Internal Buffer Zone be considered a “Consultation Zone” , where there would be an assumed presumptive right to operate in the Internal Buffer Zone unless COGCC staff and CDPHE can demonstrate that allowing the operator to operate in the zone will result in inadequate protection of public health, welfare, and the environment. The Commission considered this proposed “Consultation Zone” approach and rejected it, concluding that public drinking water is among the most significantly valued resources in Colorado and as a result must enjoy paramount protection. Thus, Rule 317B reflects the Commission’s policy that it is entirely appropriate that new operations are not to be allowed in the Internal Buffer Zone without an operator requesting a variance and meeting high standards for receiving one, as discussed below. The Commission also considered rule language reflecting the basis for granting variance requests, particularly those requests involving a demonstration of “substantially equivalent protection of drinking water quality” . In doing so, the Commission deliberately did not specify which BMPs would be required to meet variance criteria because of widely varying site-specific circumstances encountered at oil and gas locations. The intent of this rule language is to allow operators to choose BMPs necessary to meet the “substantially equivalent” test, thereby preserving their flexibility to exercise site-specific judgment. The Commission envisions that operators would identify BMPs to demonstrate how their application would result in substantially equivalent protection of drinking water quality. A few examples of what categories of BMPs might be considered to demonstrate “substantially equivalent” protection include increased monitoring frequency, limited surface disturbance, additional spill prevention, additional fluid containment, closed loop drilling procedures, protective stimulation technologies, protective chemical storage and additional tank safety procedures. The intent is to provide protection for the drinking water supply, while allowing some flexibility in exceptional cases demonstrated by the operator, using variance procedures.

The Commission recognizes that the flexibility provided by this rule requires operators to exercise judgment and does not provide certainty as to what specific protective measures may be required at each oil and gas location. Many factors may affect the selection of appropriate BMPs for a particular location and the approval of their use, including but not necessarily limited to , topographic relief, soil erosion potential, presence of vegetative or other erosion-resistant cover, facility size, local hydrology, and the nature of the materials used at the site. Many forms of guidance documents regarding the selection of BMPs for oil and gas operations are available and the Commission encourages oil and gas operators to rely on them when selecting appropriate BMPs. Examples that provide useful guidance include, but are not limited to:

- BMP manuals such as Urban Drainage and Flood Control District’s Volume III (www.udfcd.org/downloads/down_critmanual.htm) and Colorado Department of Transportation’s BMP Manual (http: Colorado Department of Transportation’s BMP Manual (http://www.dot.state.co.us/Environmental/envWaterQual/wqms4.asp) - Guidelines in BLM’s Oil and Gas Exploration and Development Gold Book - Civil engineering design manuals for roads, drainage, culverts, etc., which specify appropriate design specification for stable infrastructure.

The Commission adopted Appendix VI to this Rule 317B. It identifies the Public Water Systems that will initially be subject to the protections of Rule 317B and presents the Interim Public Water System Surface Water Supply Area Map. The Commission anticipates updating, through rulemaking, Appendix VI prior to April 1, 2009 to reflect further verification of public water system locations and the protection areas around them. Thereafter, the Commission intends to periodically update Appendix VI through rulemaking so that future public water systems are afforded protections available to them by this rule. Additionally, operators can use the Public Water Systems Surface Water Supply Area Applicability Determination Tool (located on the COGCC Web-site) to determine specifically whether and how Rule 317B applies to oil and gas locations.

The Commission also encourages staff to consider the development of additional informational guidance following the finalization of this rule, which may help operators identify additional useful reference material and select effective site specific BMPs.

2. Rule 341., BRADENHEAD MONITORING DURING WELL STIMULATION OPERATIONS Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : Almost all wells in Colorado are stimulated in some way to increase oil and gas production. Hydraulic fracturing is a stimulation technique where fluid is pumped into a well at high pressure, causing the producing rock formation to physically split (fracture) and thereby release more oil and natural gas for production from the well. Acidizing stimulates the well by pumping acid into the producing formation to eliminate scale deposits or cementing damage. Thousands of these and other types of stimulations are performed each year in Colorado with no adverse impact to groundwater or the surface environment. In a small number of cases, however, surface owners have alleged contamination of their groundwater due to these stimulation techniques. Although these allegations have never been proven by the COGCC , this rule requires operators to keep specific records regarding bradenhead pressures recorded during the stimulation process to ensure no groundwater is affected. The result is greater protection for groundwater resources and the public health, safety, and welfare. Rule 341. requires operators to monitor bradenhead pressure during the stimulation process and to report any high bradenhead pressure increase to the COGCC. Monitoring bradenhead pressures will help indicate if a hydraulic fracturing procedure or another stimulation procedure was not completely contained in the producing reservoir. A high bradenhead pressure may indicate the stimulation fluid has entered the open space between the steel well casing and the drilled hole. Any stimulation fluid entering this space could contaminate groundwater. In lieu of monitoring bradenhead pressure, the bradenhead valve may be left open to monitor the annulus. However, prior approval by the Director is required to use this alternate method in certain circumstances, and abnormal flow must be reported.

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.

400-Series Unit Operations, Enhanced Recovery Projects, and Storage of Liquid Hydrocarbons No additions or amendments were made to the 400-Series of rules. 500-Series Applicability of Rules of Practice and Procedure Amendments to the 500-Series The following rules were amended:

1. Rule 501., APPLICABILITY OF RULES OF PRACTICE AND PROCEDURE Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : This amended rule incorporates what used to be Rule 514., JUDICIAL REVIEW, into subsection c. This amendment takes into account amended Rule 305.d.(2), which clarifies that Director approval of an APD or Form 2A becomes final agency action if a hearing is not requested by those with standing in Rule 503.b.(6) within ten days after the application is approved. Those with standing will be required to exhaust administrative remedies and ask for a hearing in a timely manner before being able to seek judicial review. See Colorado Water Quality Control Commission v. The Town of Frederick , 641 P.2d 958, 964 n. 9 (Colo. 1982).

2. Rule 502., PROCEEDINGS NOT REQUIRING THE FILING OF AN APPLICATION Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : This amendment clarifies the standard for variances. The amendment makes clear that variances can be requested from rules, regulations, or orders. Prior to the amendment, Rule 502. stated variances could be requested from rules only.

3. Rule 503., ALL OTHER PROCEEDINGS COMMENCED BY FILING AN APPLICATION Basis : The statutory bases for these amendments are sections 34-60-104(2)(a)(1) and 34-60- 106(11)(a)(II), C.R.S.

Purpose: Amended Rule 503.b. expands the universe of parties who can request a hearing before the COGCC on the approval of an APD, and also allows the same parties to request a hearing before the Commission on the approval of a Form 2A. Prior to the amendments, Rule 503.b. only allowed the relevant local government to request a hearing on the approval of an APD, and Rule 303.k. only allowed the operator to request a hearing if the Director either withheld or suspended approval of such an Application. Because Oil and Gas Location Assessments were not approved, no one could request a hearing on them. As amended, Rule 503.b. allows a hearing to be requested on either the approval of an APD or Form 2A, as applicable. In addition to the relevant local government and the operator, the surface owner of the affected land, the CDPHE, and the CDOW may also apply for such a hearing. The surface owner’s right to a hearing will be limited to alleged noncompliance with the Commission rules or statute, or potential adverse impacts to public health, safety, and welfare, including the environment and wildlife resources, that are within the Commission’s jurisdiction to remedy. The CDPHE’s right to a hearing will be limited to issues regarding protection of health, safety, and welfare of the general public and the environment. The CDOW’s right to a hearing will be limited to issues involving minimizing adverse impacts to wildlife resources. The operator’s right to apply for a hearing will no longer be limited to the withholding or suspension of approval of an Application, but will also encompass matters such as the Director’s imposition of special conditions, consultation disagreements under Rule 306., and delay in making decisions under Rule 303.e. These changes reflect a policy decision by the Commission that balances a variety of competing considerations. These considerations include providing access to the COGCC for those individuals and entities that are most significantly affected by the Director’s action; such access is important because it may be more efficient, faster, and less costly than a judicial challenge. These considerations also include ensuring that the regulatory process remains timely and efficient as mandated by HBs 07-1298 and 07-1341, that the issues raised in a hearing do not exceed the COGCC’s authority, and that the COGCC is not overwhelmed by hearing applications given the thousands of approvals that are issued annually. In balancing these considerations, amended Rule 503.b. allows surface owners to request hearings, but only where they allege noncompliance with Commission rules or statute or potential adverse impacts to public health, safety and welfare, including the environment and wildlife resources, that are within the Commission’s jurisdiction to remedy. Surface owners may not request hearings merely to oppose oil and gas development or to raise issues involving reasonable accommodation or contract interpretation.

Amended Rule 503.b. will also allow the CDPHE and CDOW to request hearings, but only where the issues involve health, safety, and welfare of the general public and the environment, or minimizing adverse impact to wildlife resources, as applicable. These issues, too, are cognizable by the COGCC under the Act. This will not delegate any decision making authority to the CDPHE or CDOW. Rather, it will merely provide them with access to the Commission where they disagree with the Director’s resolution of health, safety, welfare, or wildlife issues. Such access will be equivalent to that granted to local governments and surface owners and more limited than that granted to operators. The Commission urges and expects the CDPHE and CDOW to exercise this procedural right judiciously and to request a hearing only where significant health, safety, welfare, or resource protection issues or policies are at stake. As amended, Rule 503.b. will not allow nearby landowners or members of the public to apply for a hearing. However, such persons will have various other means of providing input to the Director and COGCC regarding Applications and Assessments of concern to them. For example, members of the public can submit comments to the Director and staff under Rule 305.c. They can file a written complaint with the Director and staff under Rule 303.m. They can ask the local government or the CDPHE or CDOW to request a hearing under Rule 503.b. If a hearing is requested, they can intervene under Rule 509.a. or submit an oral or written statement under Rule 510.a.

In adopting these changes, the Commission considered a wide range of input from the parties. For example, oil land gas parties argued that standing to request a hearing before the Commission on a Form 2 or Form 2A should be limited to the operator and the local government. In contrast, environmental and wildlife groups argued that standing should be further expanded to include anyone who alleges that they would be adversely affected or aggrieved. The Commission believes that the amendments adopted reflect an appropriate balance of the competing considerations at this time.

The Commission wishes to emphasize that it expects a party that requests a hearing to specify the basis for its objection to the Director’s decision. This should include a specific description of the noncompliance with Commission rules or statute or the potential adverse impacts to public health, safety, and welfare, including the environment and wildlife resources, which the party alleges. Further, the Commission wants to make clear that it has the authority to remedy only issues that are within its jurisdiction. The Commission cannot, for example, remedy issues related to the interpretation or enforcement of surface use agreements or other contracts between surface owners and operators governing surface use or the application of the reasonable accommodation doctrine codified in section 34-60-127, C.R.S. Finally, the Commission notes that it has authority under Rule 501.b to take appropriate action in the event that a party’s use of Rule 503.b constitutes an abuse of process. Such an abuse of process may include requesting hearings on Form 2s that raise identical or substantially identical issues to those that were previously rejected by the Commission in a hearing on the Form 2A for that location or on a prior Form 2 for a well at that location.

4. Rule 507., NOTICE FOR HEARING Basis: The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose: The main purpose of these amendments is to ensure that proper notice for hearings is given to CDPHE and CDOW when appropriate. These amendments are necessary to ensure that the public health, safety, and welfare, including the environment and wildlife resources, are properly protected. If CDPHE and CDOW did not receive notice of certain applications, then the provisions of HB 07-1298 and HB 07-1341 would be undermined.

5. Rule 508., LOCAL PUBLIC FORUMS, HEARINGS ON APPLICATIONS FOR INCREASED WELL DENSITY AND PUBLIC ISSUES HEARINGS Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II) and 34-60- 128(3)(d), C.R.S.

Purpose: Rule 508. creates a public forum process for applications that: (1) would result in more than one well site or multi-well site per forty acre nominal governmental quarter-quarter section; or (2) would result in more than one well site or multi-well site per forty acre nominal governmental quarter-quarter section within existing units not previously authorized by COGCC order. Public forums may be initiated by the Commission or certain identified persons. The primary purpose of the amendments to this rule is to clarify the roles of CDPHE and CDOW in such proceedings. Neither agency could initiate a public forum, but they would be notified of, and could participate in, public forum proceedings initiated by others. Specifically, CDPHE may participate in such proceedings to raise public health, safety, and welfare issues, including protection of the environment, and CDOW may participate in such proceedings to raise wildlife resource issues. This will enable the participants in the public forum to receive input from the CDPHE and CDOW, which should help to ensure appropriate protection for the environment and wildlife resources consistent with HBs 07-1298 and 07-1341.

6. Rule 509., PROTEST/INTERVENTION/PARTICIPATION IN ADJUDICATORY PROCEEDINGS Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II) and 34-60- 128(3)(d), C.R.S.

Purpose: The primary purpose of the amendments to this rule is to clarify the roles of CDPHE and CDOW in hearings. It specifies that the entities can only intervene in hearings in which they have an interest (i.e., environmental and public health concerns for CDPHE and wildlife resource concerns for CDOW). In addition, the amendments state that parties may be directed to engage in a prehearing conference in certain circumstances. The amendment simply codifies current COGCC practice.

7. Rule 510., STATEMENTS AT HEARINGS Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: The amendment to this rule furthers public participation in the COGCC hearing process by explaining that a form for submitting a written statement regarding any COGCC matter is available on the COGCC web-site. As a matter of policy, the COGCC wants the public to participate in public business to the fullest extent possible. This amendment to the rule is an easy way to help achieve that goal.

8. Rule 511., UNCONTESTED HEARING APPLICATIONS Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II) , C.R.S . Purpose: Rule 511. pertains to hearing applications that receive no protests or interventions. In the past, administrative hearings for uncontested items were held by a COGCC hearing officer and the applicant. At that time, the hearing officer heard evidence and asked questions. As the number of applications increased, it became onerous for a hearing officer to conduct these hearings for every application. It became particularly onerous because many of the applications were identical in many relevant respects. For instance, multiple applications each month included the same pictures, the same spacing, the same basin, the same formation, and the same geologic setting. Requiring an administrative hearing on every application was not always necessary.

The amendments to this rule allow the hearings manager the ability to simplify the uncontested hearing application process when appropriate. This process is already employed in Wyoming. Specifically, the amendments give the hearings manager the ability to confer with applicants and decide between two options on the best way to deal with the uncontested application. The first method, described in Rule 511.d., codifies the current COGCC practice. Under this method, the applicant will have an administrative hearing before the hearing officer. At the end of this hearing, the hearing officer and Director may recommend approval of the uncontested application by the full Commission. This option is expected to be employed when an application is unique. The second option, described in Rule 511.c., allows the hearings manager to streamline the uncontested application process when appropriate. This option only requires that the applicant submit certain evidence to the hearing officer, but does not require an administrative hearing. At the end of the evidence review by the hearing officer, the hearing officer and Director may recommend approval of the uncontested application by the full Commission. This option is expected to be employed when all of the relevant evidence is so well-known in the industry that the need for a full-blown administrative hearing is unnecessary. These amendments result in an efficient process that is expected to save time and money for both the COGCC and all affected operators. In addition, these amendments allow all affected parties the ability to have due process in the form of a truncated hearing. Such truncated hearings are allowed in Colorado . See Colorado Water Quality Control Commission v. The Town of Frederick , 641 P.2d 958 (Colo. 1982).

9. Rule 512., COMMISSION MEMBERS REQUIRED FOR HEARINGS AND/OR DECISIONS Basis : The statutory bases for this amendment are sections 34-60-104(2)(a)(I) and 34-60- 106(11)(a)(II), C.R.S.

Purpose: By statute, the Commission now has nine members. This amendment changes the quorum from four Commissioners to five Commissioners, ensuring a majority of Commissioners are available before the Commission can transact business.

10. Rule 514., JUDICIAL REVIEW (Deleted)

Basis : The basis for this deletion is section 34-60-106(11)(a)(II), C.R.S. Purpose: This rule stated that a Commission order was considered final agency action for purposes of judicial review and that the time period for filing and appeal for such action began the day the Commission order was entered. That concept, with minor revisions, is now in amended Rule 501.

11. Rule 520., TIME OF HEARINGS AND HEARING/CONSENT AGENDA Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: The main amendment to Rule 520. (there were other clerical amendments) was added to clarify that any Commissioner may request clarification from either the Director or the attorney or other representative of the applicant for any matter on the consent agenda. In recent months, the Commissioners have expressed hesitation at approving items on the consent agenda when representatives for the applicants are not available for the Commissioners to ask questions. The amendment makes clear that an item may not be approved if the Commissioners are not able to seek the clarification for which they are looking on an item on the consent agenda. As a matter of policy, the Commissioners want to ensure that they have the ability to make the most informed decisions on all matters that come before them, which is why this addition to Rule 520. is appropriate.

12. Rule 522., PROCEDURE TO BE FOLLOWED REGARDING ALLEGED VIOLATIONS Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : Rule 522. deals with the procedures the COGCC follows when alleged violations are committed by operators.

While the COGCC can investigate alleged violations on its own, complaints that request the Director issue a Notice of Alleged Violation (NOAV) may be made by those most likely to be affected by a violation committed by an operator: the mineral owner, surface owner or tenant of the lands upon which the alleged violation took place; other state agencies; the local government within whose boundaries the lands are located upon which the alleged violation took place; or any other person who may be directly and adversely affected or aggrieved by the alleged violation. The amendments to Rule 522. fall into two general categories. First, some amendments are clarifying in nature, making sure it is clear who carries the burden of proof in hearings dealing with alleged violations. Second, some amendments deal with the policy decision of the COGCC to allow complainants a broader set of rights in alleged violation matters. Pursuant to the amendments, complainants have the right to ask for a hearing for an Order Finding Violation in certain circumstances. This right exists even if the operator and COGCC staff have entered into an Administrative Order by Consent, which is akin to a settlement agreement, on the alleged violation. The rationale for this extended right is to give the individual affected by the alleged violation more of a voice in the administrative process and to ensure the complainant has a forum to formally get information on a record if the complainant so wishes.

13. Rule 523., PROCEDURE FOR ASSESSING FINES Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II), 34-60-121, and 34-60-128(3)(d), C.R.S.

Purpose: This rule was amended for three reasons: (1) to update the base fines for rule violations while keeping within the limits in the Act; (2) to update the base fine schedule to include all new rules; and (3) to add significant damage to wildlife resources as an aggravating factor when determining the fine amount.

14. Rule 524., DETERMINATION OF RESPONSIBLE PARTY Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II) and 34-60- 124(7), C.R.S.

Purpose: The Act defines “responsible party” as “any person who conducts an oil and gas operation in a manner which is in contravention of any then-applicable provision of this article, 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 that threatens to cause, or actually causes, a significant adverse environmental impact to any air, water, soil, or biological resource. The primary purpose of the amendments to Rule 524. is to clarify that only those employees designated to accept responsibility for a company (in accordance with amended Rule 302.) can be found by the Commission as being responsible parties, as opposed to contractors of an operator. Further, potential responsible parties are clarified as being those that have or should have submitted financial assurance for oil and gas operations pursuant to the 700-Series.

15. Rule 529., PROCEDURES FOR RULEMAKING PROCEEDINGS Basis: The statutory basis for this amendment is section 34-60-108, C.R.S. Purpose : Prior to the amendments, Rule 529.c. mandated that Commission rulemaking hearings could only be noticed for 20-60 days in the Colorado Register before they commenced. The Administrative Procedure Act does not limit the number of days proposed rules can be noticed before the rulemaking hearing commences. See C.R.S. § 24-4-103. The 60-day limit was removed in order to simplify the rulemaking process (i.e., only the Administrative Procedure Act’s deadline needs to be followed). In addition, prior to the amendments, Rule 529.d. said, “The rulemaking hearing shall not be held until the expiration of six (6) months from the date of the application unless the Commission, in its discretion, decides that an earlier hearing is appropriate.” This six month period was rarely followed. Because the subsection stated the Commission could use its discretion to follow this rule, and because the six month waiting period was rarely invoked, the subsection was not useful and removing it was appropriate.

16. Rule 530., INVOLUNTARY POOLING PROCEEDINGS Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II) and 34-60-116, C.R.S.

Purpose: Involuntary pooling is a complicated issue. This amendment is an attempt by the COGCC to make the involuntary pooling process a bit clearer to both operators and mineral owners. For instance, the rule makes clear that an application for involuntary pooling can be filed at any time prior to or after the drilling of any well and that any involuntary pooling order issued by the Commission shall be retroactive to the date the application is filed unless otherwise agreed to by the payor.

Additions to the 500-Series The following rule was added:

Rule 513., GEOGRAPHIC AREA PLANS Basis : The statutory bases for this amendment are sections 34-60-104(2)(a)(I) and 34-60- 106(11)(a)(II) , and 34-60-128(3)(d)(ii) , C.R.S.

Purpose : Section 34-60-128(3)(d)(ii), C.R.S., directed the Commission to promulgate rules that address geographic area planning. Geographic area planning allows the COGCC to address potential activities by multiple operators, better identify cumulative adverse impacts caused by oil and gas operations, and require appropriate mitigation for such impacts. It also enables the COGCC to tailor regulatory standards to different areas of Colorado, which may raise different geologic, hydrologic, environmental, and wildlife issues. The Commission previously developed basin-wide rules on occasion, including Rules 318A. and 318B., but prior to the addition of Rule 513., the COGCC rules did not specify the process for, or the content of, such plans. Under Rule 513., such plans would be initiated by the Commission, and they would be adopted through a formal rulemaking process under Rule 529.

The identification of cumulative adverse impacts caused by oil and gas operations will benefit the general public, the regulated industry, and State agencies. The general public will benefit from geographic planning because it will identify activities to occur in a defined geographic area, identify potential cumulative adverse impacts, and identify appropriate mitigation for such impacts. This will result in better protection of public health, safety, and welfare, including the environment and wildlife resources. The regulated industry will benefit because the rule defines a process for adopting geographic area plans, which will include public notice, a public hearing, and consultation with CDPHE, CDOW, and the relevant local governments. During the hearing, the Commission stressed that they intend this rule to be implemented in such a way that hearings, or a portion of hearings, associated with geographic area plans should be held in the geographic area covered by the plan. Such implementation furthers the Commission’s commitment to serve all of the citizens of Colorado.

The following rule was proposed but not adopted:

Rule 521., MEMORANDA OF AGREEMENT WITH LOCAL GOVERNMENTS (Proposed but not adopted)

Basis: The statutory basis for this proposed addition is section 34-60-106(11)(a)(II), C.R.S. Purpose : Rule 521. was proposed to help address the growing concerns surrounding the issue of state preemption of local regulations. The rule laid out a procedure by which a local government could work with the Commission to enter into a memorandum of agreement regarding the interplay between the local government’s land use processes and the COGCC’s regulations. Some parties supported the proposed rule, including conservation groups and certain local governments. Other parties opposed the proposed rule, including oil and gas companies and other local governments. The issues raised included both legal and practical concerns. Because of these issues, the Commission chose not to take action upon the proposed rule at this time. Instead, the Commission directed the COGCC staff to offer to work with La Plata County on a pilot memorandum to explore how this concept would function in practice. The Commission further directed that such work should include opportunities for input from other interested parties. Depending upon the outcome of this effort, the Commission may subsequently initiate another rulemaking process to adopt proposed Rule 521 or a similar rule. 600-Series Safety Regulations Amendments to the 600-Series The following rules were amended:

1. Rule 602., GENERAL Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: This Rule discusses basic safety requirements applicable to all oil and gas operations. The amendment to this rule requires that any accident that requires medical treatment for an employee or member of the public must be reported to the Director. Further, it requires that a Form 22, Accident Report, be filed with the Director within ten days of such accident. Form 22 already exists and this amendment simply clarifies the scope of this requirement and codifies current practice.

The definitions of “medical treatment” and “first aid treatment” are taken from the definitions of these terms by the Occupational Safety and Health Administration.

2. Rule 603., DRILLING AND WELL SERVICING OPERATIONS AND HIGH DENSITY AREA RULES Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: Rule 603. concerns requirements for statewide drilling and well servicing operations and high density area rules. In addition to clerical amendments, there were primarily three subsections amended: Rule 603.e.(3), Rule 603.e.(12), and Rule 603.(j). As explained below, these amendments are intended to better protect public health, safety, and welfare, including the environment and wildlife resources. The Commission also considered proposals by certain parties and Commissioners to increase the setback distances under Rule 603.a. Instead of taking action upon these proposals, the Commission directed the COGCC staff to convene a stakeholder group during the first quarter of 2009 to discuss and attempt to develop greater consensus on an increase to the setback requirements. Based upon the outcome of this stakeholder process, the Commission may initiate a subsequent rulemaking process during 2009 to further address this issue.

a. Rule 603.e.(3) – Setbacks for production equipment Rule 603.e.(3) provides setback requirements on production tanks and production equipment in a high density area. Prior to amendment, Rule 603. did not address pits. Pits used in the oil and gas industry have the potential to impact public health, safety , and welfare , including the environment and wildlife resources. Leaking pits can impact shallow groundwater , pits that overflow or overtop can impact surface waters , and pit odors and volatile organic compound emissions can impact public health. Therefore, the amendments apply setback requirements to pits. In addition, Rule 603.e.

1. (3) used to apply setbacks only during initial installation. The amendments also apply the setbacks during construction, which is more protective of the safety of the public because it will include facility modifications and upgrades. Finally, prior to amendment, Rule 603.e.(3) required production tanks to be at least five hundred feet from certain structures only if requested by the local governmental designee. Now, the amendments require production tanks, pits, or associated on-site production equipment to be at least five hundred feet from such structures in all circumstances where the operator has legal control.

b. Rule 603.e.(12) – Berm construction Rule 603.e.(12) pertains to berm construction. Berms and secondary containment devices are used as fire walls to maintain spilled or released flammable liquids on location, which protects public health and safety. The containment devices also limit the spread of the released material which is protective of surface waters, vegetation and wildlife resources.

1. Prior to amendment, it was unclear if Rule 603.e.(12) only applied at the time berms were constructed. In addition, prior to amendment, Rule 603.e.(12) discussed berms but did not indicate that other forms of secondary containment were available and suggested that remote impounding was a preferred method of containment. Remote impounding is not a preferred method because the design and construction, operation and maintenance of retention ponds can be very difficult. The construction of ponds in high density areas is also not recommended. In addition, prior to amendment, Rule 603. did not address the permeability of the containment materials or containment area. If the berm is constructed out of highly permeable materials, then spilled or released substances may leach through and impact stormwater and surface waters. Also, if the containment area is not sufficiently impermeable then spills or releases may infiltrate and impact shallow groundwater. The rule was also clarified to confirm that it also includes produced water tanks. Finally, the old Rule did not include requirements for inspections and maintenance of secondary containment devices or berms.

   The amendments clarify that Rule 603. applies to all containment berms and not only newly-installed or replaced berms. They also require berms or secondary containment areas to be maintained in good condition. Further, language referring to remote impounding was removed and language discussing secondary containment devices was inserted. Finally, language was added to include requirements that the secondary containment berms or devices and the secondary containment areas be sufficiently impervious to contain the released material.

   As amended, Rule 603.e.(12) effectively balances development of oil and gas resources with protection of public health, safety, and welfare, including protection of the environment and wildlife resources. Berms in high density areas are currently required around crude oil, and condensate, and produced water tanks. Berms and secondary containment devices are widely implemented throughout the oil and gas industry to promote safety and protect the environment.

c. Rule 603.j. – Statewide equipment, weeds, waste, and trash requirements Waste disposal and burning of waste materials are covered under federal and state statutes. Additionally, local governments may have waste disposal requirements, restrictions on burning of materials and waste management regulations. Compliance with waste disposal laws is complicated and, prior to the amendment, the rule was oversimplified and misleading. Improper disposal of waste materials can impact public health, safety, and welfare, including the environment and wildlife resources. It also has the potential to create a regulatory and liability issue for the surface owner, who might inadvertently allow the unlawful burial or burning of waste material.

d. “Occupied” building amendment Prior to amendment, Rule 603.a.(1) and 603.b. included the term “occupied” building. There was no definition for “occupied” , which created the potential for misinterpretation of setback and high density requirements. For example, residential structures that are seasonally occupied may not have been included in review when operators were determining whether a site was in a high density area, and appropriate setbacks might not have been employed. These portions of Rule 603. were amended to include the term “building unit” , which is defined in the 100-Series.

3. Rule 604., OIL AND GAS FACILITIES (formerly PRODUCTION FACILITIES) Basis : The statutory bases for these amendments are sections 34-60-106(11)(a)(II) and 34-60- 128(3)(d), C.R.S.

Purpose : Rule 604. deals with the requirements applicable to all oil and gas facilities. The amendments add new requirements that will provide more protection for public health, welfare, and safety, including the environment and wildlife resources. The non-clerical amendments are described below.

a. Rule 604.a. – crude oil and condensate tanks Rule 604.a. was revised to clarify that the tank specifications and secondary containment requirements refer to condensate tanks and crude oil tanks whereas previous regulations only referenced crude oil tanks.

1. Prior to amendment, Rule 604.a.(3) included a requirement that tanks be a minimum of 200 feet from “residences, normally occupied buildings, or well defined normally occupied outside areas.” There was no definition for those terms, which created a potential for misinterpretation of statewide set back requirements. This rule has been amended to replace those terms with “building unit” , which is defined in the 100-Series.

b. Rule 604.b. – fired vessel, heater-treater Rule 604.b. was amended by the addition of Rule 604.b.(7), which specifically addresses the protection of migratory birds. The U.S. Fish and Wildlife Service, Office of Law Enforcement, determined that heater-treaters associated with oil and gas operations create a widespread environmental hazard to migratory birds. The Migratory Bird Treaty Act (MBTA) of 1918, as amended, implements various treaties and conventions between the U.S. and other countries for the protection of migratory birds. Under the MBTA, the taking, killing, capturing, or possessing migratory birds, whether intentionally or unintentionally, is unlawful. After March 1, 2007, responsible parties that contribute to migratory bird deaths in heater-treaters will be subject to criminal prosecution resulting in up to a $15,000 fine per bird mortality and six months ' imprisonment. See U.S. v. Apollo Energies, Inc. and Dale Walker d/b/a Red Cedar Oil , Slip. Op., 2008 WL 4369300

1. (D. Kan. 2008).

   Rule 604.b.(7) is designed to provide additional protection to biological resources by requiring operators to equip fired vessels, including heater-treaters, with screens or other devices to prevent migratory birds from entering stacks, vents or other openings. This is consistent with the General Assembly’s mandate that the COGCC establish standards for minimizing adverse impacts to wildlife resources affected by oil and gas operations. The Commission previously adopted a number of rules that require operators to conduct various activities associated with oil and gas operations so as to protect biological resources. The intent of the new rule language is to clarify the type of equipment (i.e., equipment designed to prevent entry by wildlife, including migratory birds) that should be used to cover openings. It is not intended to imply that a rule violation will occur automatically if wildlife gets into stacks, vents, or other openings that are equipped with properly installed equipment. The Commission stresses, however, that while a rule violation may not occur in such a case, operators are still subject to the provisions of the MBTA and might be found criminally liable under that statute.

c. Rule 604.e. – buried or partially buried tanks, vessels or structures Rule 604.e. was amended to add a requirement that buried or partially buried tanks, vessels, or structures not only be properly designed and installed but also properly operated. This change was necessary to clarify the application of Rule 604.e., and to further public health, safety, and welfare.

d. Rule 604.f. – produced water pits, special use and buried or partially buried vessels or structures Rule 604.f. is a new subsection that adds a statewide setback requirement of 200 feet for produced water and special use pits and buried or partially buried vessels or structures. This addition provides additional protection for public health, safety, welfare. In addition, amended Rule 604.f provides additional protection to the environment by requiring operators to provide adequate secondary containment for bulk oil containers and tanks. This is also consistent with the General Assembly’s mandate to minimize adverse impacts to wildlife resources.

Additions to the 600-Series The following Rule 608. was added:

Rule 608., COALBED METHANE WELLS Basis: The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose : Since the onset of coalbed methane (“CBM” ) production in Colorado, there have been instances where improperly plugged and abandoned (“P&A” ) oil and gas wells, unplugged orphaned wells, and conventional wells in which the coal seams have not been properly isolated have acted as conduits for the migration of CBM gas into groundwater and surface water and to the ground surface. In addition, the seepage of methane from the outcrops of the coal seams has the potential to create explosive conditions if it accumulates in confined spaces and to stress and kill vegetation , thereby impacting wildlife habitat and property values. Since methane is a colorless and odorless gas, even at explosive concentrations, it can go unnoticed unless testing and monitoring equipment are used to detect its presence. The COGCC has regulated CBM wells since 1990 by adopting numerous orders, including 112- 156, that require operators of CBM wells in the Colorado portion of the San Juan Basin to conduct various monitoring activities, including, but not limited to : bradenhead pressure testing; water well sampling and analysis; coal outcrop, gas seep, and spring mapping and testing; assessment of plugging procedures for and soil gas surveys around previously P&A wells; and post completion pressure build-up testing. Rule 608. codifies these orders and expands their application to operators of all CBM wells regardless of their location, thus providing the COGCC with a mechanism to obtain data consistently across the state. These data will be used to verify that water wells, ground and surface waters, and residents of the CBM producing basins are adequately protected and that impacts, should they occur, are quickly identified and mitigated. Rule 608. requires operators to assess and to monitor P&A wells within one-quarter mile of proposed CBM wells. The Commission heard testimony that there have been two relatively recent incidents involving the migration of methane, one up a P&A well and another up an orphaned well. These incidents resulted in accumulation of methane in homes, causing explosions and personal injuries. If Rule 608. had been in place when those incidents occurred, it is likely that this migration would have been detected and mitigated.

In addition, operators are required to conduct soil gas surveys around these wells periodically to identify any changes. This periodic monitoring is crucial because initially there may not be any gas detected around a plugged and abandoned or orphaned well, but as production in the nearby CBM wells continues and gas begins to desorb from the coal seams, the gas may eventually find a migration pathway up the old wellbore into aquifers and to the ground surface. Rule 608. also requires operators to monitor water wells in proximity to conventional, plugged and abandoned, or CBM wells to determine whether the drilling, completion, and production of the CBM are having an effect on the groundwater resources of the area. The Rule also states that if a proposed CBM well is within two miles of the outcrop of the stratigraphic contact between the coal-bearing formation and the underlying formation or within two miles of a coal mine, the operator will be required to conduct coal outcrop and coal mine monitoring. The Commission heard testimony that in recent years methane seepage in some areas of Colorado appears to have increased dramatically. Where seepage is substantial, methane gas has the potential to accumulate and create a risk of explosion to structures and people. The methane in these areas also has the potential to migrate into groundwater and affect water wells. Operators will be required to equip well heads with appropriate and safe fittings to access the annular space between the production casing and the surface casing and any intermediate casing. This will allow the safe and convenient measurement of pressure and fluid flow. Bradenhead tests will be performed on all wells on a biennial basis unless the operator meets certain conditions described in Rule 607.e. The Commission heard testimony that in the San Juan Basin bradenhead testing has been instrumental in the identification and subsequent remediation of defective wellbores and other mitigation strategies. Bradenhead tests are relatively inexpensive and are a quick way to identify wells that may not have complete isolation of the gas producing zones from overlying aquifers and other formations. There is an indication from the analytical data obtained from the water well sampling program in the San Juan Basin, that methane concentrations in groundwater in certain areas appear to be decreasing. This decrease presumably is a result of the remediation of defective wellbores and the plugging and abandonment of orphaned wells.

The final version of Rule 608. reflects significant revisions to the rule as initially proposed. The Commission believes that as revised Rule 608. will help ensure that CBM development occurs in a responsible and balanced manner that will protect public health, safety, and welfare, including the environment and wildlife resources. The Commission also wishes to emphasize that the survey and monitoring requirements in Rule 608. are informational, and Rule 608. does not create new obligations for operators to remedy seepage of methane at outcrops or coal mine locations, nor does the rule itself impose liability upon the operators for such seeps. 700-Series Financial Assurance Amendments to the 700-Series The following rules were amended:

1. Rule 703., SURFACE OWNER PROTECTIONS Basis : The statutory bases for this amendment are sections 34-60-106(3.5), 34-60-106(11)(a) (II), 34-60-106(13), and 34-60-128(d)(II), C.R.S.

Purpose: Prior to amendment, Rule 703. required operators to provide financial assurance to protect surface owners who are not parties to a mineral lease, a surface use agreement, or other relevant agreement. This financial assurance is required to be posted to protect surface owners from “unreasonable crop losses or land damage” . C.R.S. § 34-60-106(3.5). The pre-amendment bonding amounts varied on the type of land owned by the surface owner. Those bonding amounts were not increased. Instead, the rule was amended to clarify that an operator is financially responsible for damages to the surface owner’s land if the amount of damage exceeds the amount of the financial assurance that was provided to the Commission. During the hearing, industry expressed concern that if this was not clarified, the Commission might instead use the Oil and Gas Conservation and Environmental Response Fund to pay for the damages. As the industry funds the Oil and Gas Conservation and Environmental Response Fund, the industry wanted it to be clear that only the individual operator would be liable for the damages.

2. Rule 704., CENTRALIZED E&P WASTE MANAGEMENT FACILITIES Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II), 34-60-106(13), and 34-60-128(d)(II), C.R.S.

Purpose : The financial assurance amount for these facilities was raised from $50,000 to an amount equal to : the estimated cost necessary to ensure the proper reclamation, closure and abandonment of such facility as set forth in Rule 908.g.(1) ; or an amount voluntarily agreed to with the Director ; or an amount determined by order of the Commission. During the rulemaking process, the Commission received testimony that there are twenty-one active centralized E&P waste management facilities. Eight of these facilities are primarily landfarms treating impacted soils or drilling muds and cuttings. The other thirteen are located on the western slope and are evaporative ponds or water storage sites for the disposal or recycling of produced water.

Maximum capacity for these evaporative ponds or water storage sites range from 75,000 to 420,000 barrels. Estimated transportation and disposal costs for these maximum volumes would range from $450,000 to $2,520,000. Estimated transportation and disposal costs for ¼ of the maximum volumes would range from $112,000 to $630,000. Estimated costs to close and reclaim the permitted centralized facilities in most cases far exceed the $50,000 financial assurance that was required prior to the amendment.

Operators of centralized E&P waste management facilities permitted prior to May 1, 2009 on federal land and April 1, 2009 on all other land will be required to be in compliance with amended Rule 704. by July 1, 2009.

3. Rule 706., SOIL PROTECTION AND PLUGGING AND ABANDONMENT Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II), 34-60-106(13), 34-60-121, and 34-60-128(d)(II), C.R.S.

Purpose: Rule 706. was amended to update the required amounts of financial assurance posted for active oil and gas wells as well as prior to the drilling of wells. Every oil and gas operator in Colorado must post financial assurance to “ensure the protection of the soil and the proper plugging and abandonment of the well” . During the rulemaking process, the Commission received testimony that the amounts of financial assurance had not increased since 1996 and did not accurately reflect the current cost of plugging and abandoning a well. This testimony further indicated that since 1996 the COGCC has plugged and reclaimed well sites using the money from 36 bonds posted by operators. The total plugging and reclamation costs for these wells were $984,968 while the total amount from bond claims was $498,907, indicating the short fall of the bonding levels.

In response, the amended rule increases the amount of financial assurance posted for individual wells from $5000 per well to $10,000 for shallow wells below 3000 feet of depth, or $20,000 for wells drilled deeper than 3000 feet of depth. The rule also increases statewide blanket financial assurance from $30,000 to $60,000 for oil and gas operators that operate less than 100 wells. The rule did not change the financial assurance amount for operators that operate more than 100 wells because that amount ($100,000) more accurately reflects the actual plugging costs in the state.

The increase in bonding levels will result in less state money being expended for plugging operations. Although the State has the Oil and Gas Conservation and Environmental Response Fund to provide funds that can be used for the plugging and abandonment of orphaned wells, as well as other environmental cleanup, and this fund may be used by the State for projects supervised by the State, higher financial assurance levels will minimize the necessity to draw on this fund. Further, the Commission heard testimony that this addition is consistent with financial assurance levels in Wyoming, Utah, and New Mexico.

After receiving testimony on both sides of the issue, the Commission chose to apply the amended financial assurances to existing wells (except domestic gas wells). If an operator finds itself in a situation where it cannot meet the requirements of Rule 706., Rule 706.c. specifies that an operator can seek a variance from this provision. A variance may be appropriate if surety bonds for the increased amount are not commercially available upon reasonable terms. Oil and gas wells (except domestic gas wells) with financial assurance posted prior to May 1, 2009 on federal lands and April 1, 2009 on all other lands must have financial assurance in compliance with amended Rule 706. by July 1, 2009.

4. Rule 707., INACTIVE WELLS Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II), 34-60-106(13), 34-60-121, and 34-60-128(d)(II), C.R.S.

Purpose : Rule 707. was amended to update the required amounts of financial assurance posted for inactive oil and gas wells. Because this Rule is dependent on financial assurance amounts required by Rule 706., Rule 707. needed to be amended to be consistent with Rule 706. The amended rule updates financial assurance calculations for operators with inactive wells. COGCC regulations require operators to post additional bonding when the number of their operated inactive wells exceeds the possible number of plugging jobs their blanket financial assurance will cover. Inactive wells are defined as any well that is shut-in or temporarily abandoned for a specific time period. Additional financial assurance may be required if an operator’s posted financial assurance is less than the theoretical plugging liability of their inactive wells multiplied by the appropriate individual plugging bond that would need to be posted for the inactive wells. The amended rule increases the individual plugging bond amounts to be in conformance with the higher bond amounts required by rule 706. The increase in bonding levels will result in less State money being expended for plugging operations. Although the State has the Oil and Gas Conservation and Environmental Response Fund to provide funds that can be used for the plugging and abandonment of orphaned wells, as well as other environmental cleanup, and this fund may be used by the State for projects supervised by the State, higher financial assurance levels will minimize the necessity to draw on this fund.

5. Rule 708., GENERAL LIABILITY INSURANCE (formerly PUBLIC HEALTH, SAFETY AND WELFARE)

Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II), 34-60-106(13), 34-60-121, and 34-60-128(d)(II), C.R.S.

Purpose : Rule 708. was amended to more accurately reflect potential liability amounts. The prior distinction between high density and non-high density areas was determined to be unnecessary for this purpose and so the rule was amended to eliminate the distinction.

6. Rule 709., FINANCIAL ASSURANCE Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II), 34-60-106(13), 34-60-121, and 34-60-128(d)(II), C.R.S.

Purpose : Rule 709. was amended by the addition of subsection d., which states that the Director will not approve a new Operator Registration or a new Certificate of Clearance when wells are sold or transferred until the successor operator has filed satisfactory financial assurance under the 700-Series rules. The amendment is necessary to ensure continued responsible practices at an existing oil and gas location by new operators. The assurance of such continued responsible practices will protect public health, safety, and welfare, including the environment and wildlife resources.

7. Rule 710., ENVIRONMENTAL RESPONSE FUND Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II), 34-60-106(13), 34-60-121, and 34-60-128(d)(II), C.R.S.

Purpose: The purpose of this amendment is to keep the language of the rule consistent with section 34-60-122, C.R.S., as amended. First, House Bill 05-1285 combined the Oil and Gas Conservation Fund and the Environmental Response Fund into one fund, the Oil and Gas Conservation and Environmental Response Fund. Second, Senate Bill 06-142 put a $4 million cap on the two year average of the un-obligated portion of the combined fund. Amended Rule 710. reflects these legislative changes.

Additions to the 700-Series The following Rule 712. was added:

Rule 712., SURFACE FACILITIES AND STRUCTURES APPURTENANT TO CLASS II COMMERCIAL UNDERGROUND INJECTION WELLS Basis : The statutory basis for this rule is section 34-60-106(13), C.R.S. In addition, there exists a Memorandum of Understanding (“MOU” ) between the Hazardous Materials and Waste Management Division (HMWMD) of the CDPHE and the COGCC regarding the disposal of eligible wastes at Commercial Class II Injection Wells. In accordance with the MOU, the HMWMD will defer to COGCC regulation of E&P wastes at Class II commercial injection well disposal sites, including COGCC regulation of E&P wastes placed in surface structures appurtenant to such wells, prior to disposal of Class II wastes down the well. Purpose: This rule requires financial assurance for operators of Class II Underground Injection Control wells in the amount of $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. This rule applies 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. A separate financial assurance requirement still applies for the plugging and abandonment of such wells as specified in Rule 706. As one example of the need for this rule, there was testimony during the hearing that Conquest Oil Company operates five commercial Class II UIC wells in Weld County. Operations at these facilities have resulted in impacts to soils and shallow groundwater beneath two of these sites. In each case, there has been a Site Investigation and Remediation Workplan, Form 27, submitted to and approved by COGCC staff. Remediation and groundwater monitoring at these sites is ongoing. Currently, Conquest Oil Company only has a $30,000 blanket plugging bond posted with the COGCC, which is not sufficient.

800-Series Aesthetic and Noise Control Regulations Amendments to the 800-Series The following rules were amended:

1. Rule 803., LIGHTING Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: Rule 803. used to refer to “occupied” buildings. There was no definition for “occupied” , which created a potential for misinterpretation of set back and high density requirements. This term was amended to “building unit” , which is defined in the 100-Series.

2. Rule 804., VISUAL IMPACT MITIGATION Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II) and 34-60- 128(3)(d), C.R.S.

Purpose: Prior to amendment, Rule 804. exempted production facilities constructed or substantially repainted prior to May 30, 1992, from mitigating visual impacts. As amended, the rule mandates that all long-term production facilities be painted to minimize visual impacts from a location typically used by the public such as a public highway. This amendment is consistent with the recent legislative mandate to protect public welfare and minimize adverse impacts to wildlife resources. Mitigating visual impacts will improve the appearance of the scenic landscape and thus benefit the general public. In addition, production facilities painted with uniform, non- contrasting, non-reflective color tones, and with colors matched to but slightly darker than the surrounding landscape may lessen impacts upon wildlife activity. Recognizing the need for operators to have sufficient time to implement this requirement, the Commission deferred its effective date until September 1, 2010.

Additions to the 800-Series The following Rule 805. was added:

Rule 805., ODORS AND DUST Basis: The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose : The Commission adopted Rule 805. to respond to increasing concern over odors and nuisance-like conditions where oil and gas development occurs near residences, neighborhoods, and other occupied structures. Testimony during the hearing confirmed that growth in oil and gas development has caused noteworthy increases, particularly in the Piceance Basin (Garfield, Mesa, and Rio Blanco Counties), in complaints about odor and impacts on the use and enjoyment of property. For example, state and local government complaint logs showed that from 2004 to 2007, Garfield County received 374 complaints, 94 of which were oil and gas- related odors (25%). From 2006 to the present, the COGCC received 496 complaints, 121 of which were oil and gas-related odors (24.3%). The Commission believes Rule 805. strikes a balance between allowing resource development and protecting public welfare by allowing the oil and gas development to occur near residences and other populated buildings, provided that certain development activity/equipment employ air emissions controls and work practices that reduce odor causing pollutants to enter the air.

Odors can emanate from day-to-day operations of the oil and gas equipment. Rule 805. addresses odor-related concerns from day-to-day operations in the three Piceance Basin Counties: Garfield, Mesa and Rio Blanco, by requiring emission controls to be placed on certain odor causing equipment (tanks, pits and glycol dehydrators) located within ¼ mile of residences or occupied dwellings. The rule also requires operators to hold a valid permit from the CDPHE for affected tanks and glycol dehydrators to assure rule effectiveness and enforcement capabilities. The Commission recognizes that without such a permit requirement, there would be little assurance that required emission control devices are installed and operated properly, rendering the rule essentially ineffective and unenforceable. The Commission understands that the operational requirements that are typically in Air Pollution Control Division permits to ensure rule effectiveness would include: (1) a requirement that control equipment be correctly piped to the control devices; (2) a requirement that control equipment be correctly sized to handle the emissions being controlled; (3) a requirement that all vents or thief hatches be appropriately sealed; (4) confirmation that the control devices are operational; and (5) verification that the pilot lights for the equipment are working.

Odors can also emanate from “flowback” occurring during the well completion phase. Prior to the adoption of Rule 805., well completion practices included allowing well contents to flow into open tanks or pits, thus allowing natural gas and condensate to disperse into the atmosphere. This practice not only creates odors but also disperses methane, a greenhouse gas, to the atmosphere, which can be a waste of valuable natural resources. The rule addresses this by requiring operators to use green completion practices, where practicable, to reduce odors and methane emissions associated with well development.

Compliance with certain provisions of Rule 805.b.(2)A, B, and C requires purchase and installation of control equipment on both existing and new oil and gas equipment if the operations are in certain locations and if certain conditions are met. Because existing condensate tanks, crude oil and produced water tanks and glycol dehydrator are subject to this rule, the Commission decided to phase in the rule’s effectiveness to allow for equipment to be ordered and installed. Specifically, operators will not be required to comply with requirements for condensate, crude oil and production tanks, or glycol dehydrators until October 1, 2009, giving operators ample time to order and install the control equipment.

Compliance with Rule 805.b.(2).D is required only for qualifying pits constructed after May 1, 2009 on federal land or after April 1, 2009 on all other land because the Commission does not intend for pits in existence on those dates to be moved or eliminated. The Commission wrote Rule 805.b.(2). A, B and C to expressly apply to existing equipment. This approach is necessary because it is the best way to respond to existing odor complaints and public welfare concern, raised repeatedly in hearing testimony. The Commission believes applying these rule sections retroactively is not only necessary, but strikes a balance between oil and gas development and public health, safety, and welfare protection. The Commission also notes that because the legislative declaration in the Act represents a remedial change, it thereby allows rules that pertain to the protection of public health, safety and welfare to be applied to existing operations. See In re Estate of Moring v. Colo. Dep’t of Health Care Policy & Fin. , 24 P.3d 642 (Colo. App. 2001). In short, the evidence presented during the hearing regarding the existing negative impacts odors are having on public health, safety, and welfare bolstered the Commission’s belief that this problem is best remedied by applying this rule to existing oil and gas operations.

The Commission also included provisions requiring operators of control equipment installed pursuant to 805b.(2)A, B and C to hold a valid permit from the CDPHE Air Pollution Control Division (APCD). The Commission believes an APCD permit is necessary to assure odor control equipment is not only installed at the site, but operated in a manner that actually reduces the odor causing VOCs. Without this provision there would be no mechanism for requiring the emission control equipment to operate properly; in other words there would be no method for enforcing against an operator who does not operate the control equipment in compliance with these provisions. The Commission’s intent here is to ensure that APCD issued permits for this equipment contain uniform and reasonable conditions that address the requirements described above.

After hearing testimony from a variety of parties during the hearing, the Commission concludes that adoption of Rule 805. will result in greater public welfare protections in the three counties within the Piceance Basin where such protections are most needed. It also believes that the adopted provisions provide the basis for protections elsewhere if and when the need arises and would consider using Rule 805. as a foundation for expanding its applicability through a subsequent rulemaking. The public welfare protections reflected in these amendments result from reduced emissions of volatile organic compounds from the larger-emitting oil and gas production sources located near human-occupied structures. Limiting the dispersion of these compounds benefits people living in the area with cleaner air that has a much lower likelihood of affecting the use and enjoyment of their property in proximity to oil and gas operations. The Commission also notes the additional benefit of limiting the greenhouse gases released to the atmosphere, and preserving the natural resources of the state that would result from these regulations. Applying a ¼ mile radius for application of the relevant emissions control requirements will afford a significant benefit for persons in occupied structures within that area in this region, and will also provide a benefit to persons beyond that radius, for example, in such structures between ¼ and ½ mile radius of that same equipment.

The Commission also finds that Rule 805. will not hinder the oil and gas industry’s ability to develop oil and gas resources. The control equipment contemplated by Rule 805. is commonly used, and the record shows operators voluntarily use this equipment to reduce impacts on the nearby populations. Rule 805. does not require specialized equipment on wells that do not produce at a sufficient volume and pressure to flow through this equipment, making it a narrowly tailored rule. Rule 805. also allows operators to request a variance if they believe employing control equipment or green completion practices or other control equipment is not feasible. In instances where green completions are not technically feasible or are not required, operators shall employ BMPs to reduce odor causing emissions.

After reviewing the record , the Commission believes Rule 805 . effectively balances the protection of public welfare with the development of oil and gas resources by minimizing hydrocarbons released to the atmosphere in proximity to occupied structures while allowing operators to continue to complete wells and operate in a normal manner. Upon consideration of all of the evidence, the COGCC concludes that these regulations as adopted are responsive to the directives set forth in HB 07-1341 .

The Commission also heard testimony regarding the need for , and recognizes the value of , studies to better understand the impacts on Colorado citizens of oil and gas development. The evidence in the record reflects questions and concerns about public health effects of oil and gas operations. The Commission believes that it would be beneficial to develop additional information regarding the relationship between oil and gas development and public health, particularly where such industrial development occurs in close proximity to residential developments. The Commission therefore is instructing staff, in collaboration with the CDPHE, to initiate a public health literature review to determine the status or current information and knowledge about this issue, identify data gaps, and guide the definition and scope of future targeted public health studies; and to report back and offer recommendations to the Commission during in the last quarter of 2009 .

The Commission also acknowledges a need to fill significant air quality data gaps from oil and gas activities in the oil and gas regions of Colorado, especially in the western Colorado oil and gas basins. This is true both for air quality monitoring data, as well as projected air quality loading and airshed impacts, typically evaluated via modeling exercises. These data gaps need filling to facilitate effective air quality planning. Specifically, the Commission believes there is a need for monitoring data to characterize current air quality conditions and to monitor the air quality impacts of oil and gas-related activities into the future. This need stems from the rapid and broad growth in oil and gas activities in the last five years in western Colorado and neighboring states, and the projected future rapid growth in oil and gas activities over the next 20 or more years, combined with the new, more stringent national ambient air quality standard for ozone. The collection of this data can provide a scientific basis for further mitigation efforts if necessary to prevent degradation of the state’s air quality or addressing potential non-compliance with health-based air quality standards that could arise from this significant and widespread industrial activity. The Commission directs staff to work with parties to this rulemaking to define air quality information needs and methods and costs for meeting them; and report back by the fall of 2009. The Commission intends for staff to develop recommendations in collaboration with CDPHE and using appropriate means . The Commission understands that agency resources are limited at this time, and that resources from the oil and gas industry as well as those of other government agencies may be available . The Commission expects that, if appropriate, recommendations may include a strategic plan for conducting and funding monitoring and studies. Condensate tanks, crude oil and produced water tanks, and glycol dehydrators within ¼ mile of certain building units that are in existence on May 1, 2009 on federal land and April 1, 2009 on all other land must be in compliance with amended Rule 805. by October 1, 2009. 900-Series Exploration and Production (E&P) Waste Management General Introduction to 900-Series The rules and regulations of the 900-Series establish the permitting, construction, operating and closure requirements for pits, methods for managing E&P waste, procedures for spill/release response and reporting, and sampling and analysis requirements for remediation activities. These rules have been developed to fulfill the COGCC’s mission to foster the responsible development of oil and gas resources and to protect public health, safety and welfare including protection of the environment and wildlife. The 900- Series rules are applicable only to E&P waste, as defined in section 34-60-103(4.5), C.R.S., or other solid waste where the CDPHE has allowed remediation and oversight by the Commission. The COGCC is an implementing agency for water quality standards and classifications adopted by the Water Quality Control Commission (WQCC) for groundwater protection. This authority was provided by Senate Bill 89-181, and is restated and clarified by a Memorandum of Agreement between the agencies. The jurisdictional authority over exploration and production waste was granted to the COGCC through Senate Bill 95-017. The occurrence and distribution of Colorado’s water resources are linked to its geography and underlying geology. The ultimate source of groundwater is recharge through precipitation. Precipitation that does not evaporate or immediately flow into surface waters percolates into groundwater . Groundwater is the primary water source for 75% of the public water supply systems in the state. The increasing reliance on groundwater by public and domestic water wells and private water systems in a water-short state mandates a greater degree of protection for groundwater quality.

Retroactive Applicability of 900-Series The Commission expressly intends that the amendments to the 900-Series Rules not be retroactive, except where specifically stated (e.g., skim pits). Moreover, the Commission notes that the future closure and remediation of pits existing on or after May 1, 2009 on federal land or on or after April 1, 2009 on all other land will be subject to the concentration levels of Table 910-1, as amended. Nonetheless, the Commission recognizes that there is a large and growing number of E&P waste management operations in Colorado, including more than 10,000 pits. The Commission also acknowledges that pits existing at the time these rules become effective (May 1, 2009 for federal lands and April 1, 2009 for all other lands) must be managed such that public health and the environment are protected. To this end, the Commission directed staff to exercise, where appropriate, its existing authority under Rule 901.c., which allows the Director to, with reasonable cause, impose additional requirements on existing pits. This rule establishes that, if the Director observes an act or practice being performed which may violate Table 910-1 or water quality standards or classifications established by the WQCC, he 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. The Commission directs staff to implement a two phase approach for implementing its existing authority under Rule 901.c with respect to existing pits. First the COGCC staff will review existing information to identify existing pits from which seepage may be reaching the underlying aquifer or waters of the state at contamination levels in excess of applicable standards or which may otherwise be violating Table 910-1 or water quality standards or classifications established by the WQCC. The staff will then require the operators of such pits to submit appropriate information demonstrating that such seepage or other violations are not occurring. Second, the staff will review the information that is submitted in response to this requirement to determine whether there is reasonable cause to believe that seepage is reaching the underlying aquifer or waters of the state at such contamination levels or that the pit is otherwise violating Table 910-1 or water quality standards or classifications. If the staff finds reasonable cause for such belief, then it will require the operator to take appropriate corrective action, which may include closing or lining the pit. The staff will develop a schedule for implementing this approach, which will reflect both the need to protect public health and the environment and the time required for staff to review existing and responsive information and for operators to develop information and take corrective action. The Commission understands that this work may require the staff to obtain additional funding. Commission requests staff to report on these efforts at least quarterly during regularly scheduled Commission meetings.

Amendments to the 900-Series The following Rules were amended:

1. Rule 901., INTRODUCTION Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : Rule 901. provides a general discussion of overall objectives of the 900-Series Rules and responsibilities for oil and gas operators. The rule provides a detailed discussion of the additional requirements that the director may impose and what actions could trigger these additional requirements.

The Commission amended the rule to expand the method for identifying sensitive areas. The Commission wishes to emphasize that this expanded methodology is needed to protect the environment, surface water and groundwater resources. Operators will be required to provide appropriate geologic and hydrogeologic data to evaluate the potential for impact to groundwater and surface water rather than use the existing Sensitive Determination Decision Tree. This evaluation will improve sensitive area determinations by, among other things, causing operators to take the complex geology and hydrogeology into account along with identifying key indicators of sensitive environmental areas including wetlands, seeps, springs, surface water features, and groundwater protection areas and designated groundwater basins. Prior to amendment, Rule 901.d. implied that risk-based approaches could be proposed as an alternate cleanup goal. There are no other provisions for risk-based approaches in the rules, and the COGCC staff testified that it has never approved such an approach. Testimony also indicated that risk-based corrective action programs are only successful at protecting public health, safety welfare and the environment through knowledge of and rigorous controls on future property uses. As the implementing agency for groundwater standards pursuant to Senate Bill 181, the COGCC is required to implement and enforce groundwater standards as established by the WQCC. Any modifications of these standards could require a hearing before the WQCC. Amended Rule 901.d. no longer refers to “risk-based approaches” and, therefore, avoids potential regulatory confusion The Commission understands from COGCC staff testimony that the Sensitive Area Determination Decision Tree (Figure 901-1) which existed prior to this amendment was not adequate to evaluate the potential for oil and gas operations to impact water resources. For instance, this simplistic approach allowed a site where groundwater is greater than 20 feet below total pit depth to be considered a non-sensitive area even if the site were underlain by an unconfined aquifer or recharge zone such as the outcrop area of the Ogallala Formation and aquifer in eastern Colorado. Under amended Rule 901, the Sensitive Area Determination Decision Tree will no longer be used for this purpose. Instead, an operator must present appropriate geologic and hydrogeologic data to evaluate the potential for impacts to groundwater or surface water. If the data indicates that the potential is high, the site is likely located in a sensitive area. If the data indicates that the potential is low, the site may be considered a non-sensitive area.

2. Rule 902., PITS – GENERAL AND SPECIAL RULES Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : Rule 902. covers general and special rules for the operation and maintenance of pits used for exploration and production of oil and gas. Rule 902. introduces and explains the requirement that pits be constructed and operated in manner that is protective of public health, safety, and welfare, including the environment and wildlife resources. It also includes a series of preventive measures.

The Commission heard testimony about pit overfills that have resulted in discharges of the pit contents to the environment, and that COGCC staff members have responded to numerous complaints regarding pit odors. The source of the odors is often: oil or condensate on the pits that has not been removed by the operator; or residual oil around the edge of the pit that remains even after the pit has been skimmed. COGCC staff members have also responded to complaints associated with odors created by bacterial growth in pits. The amendments require operators to develop a method for monitoring and maintaining freeboard, which should reduce the incidence of spills and releases caused by overtopping pits. This requirement should also benefit the industry by reducing its exposure to the costs for the remediation of spills and releases to the environment. Examples of freeboard monitoring methods include simple, low-cost methods such as painting a line on the pit wall. The amendments also require operators to clean residual oil or condensate from the edge of the pit. This requirement not only reduces a potential source of nuisance odors, but also removes a risk to wildlife, especially migratory birds, and the potential fines associated with migratory bird mortalities. The amendments also require operators to treat the contents of pits when necessary to control the growth of bacteria, which will reduce another potential source of nuisance odors. Amended Rule 902.e. provides that pits used for storage, recycling, reuse, treatment or disposal of E&P waste or fresh water may be permitted under Rule 903 to service multiple wells, subject to Director approval. This clarifies and continues the Director’s existing authority to permit pits that serve multiple wells under Rule 903 rather than as centralized E&P waste management facility under Rule 908. The Commission decided as a policy matter to continue this authority because of concern that the definition of centralized E&P waste management facility may encompass pits for which the regulatory requirements of Rule 908 outweigh the public health, safety, and welfare risks. The Commission was also concerned that eliminating this authority could deter operators from consolidating pits and fluids and thereby cause additional surface disturbance. The Commission also wants to ensure that this authority is exercised judiciously, and that pits that would meet the definition of a centralized waste management facility are permitted under the less protective provisions of Rule 903. only if this will not result in greater impacts to public health, welfare and the environment. The Commission expects the Director in exercising this authority to consider the following factors when determining applicable permitting requirements: characteristics and volume of the waste to be placed in the pit, the anticipated length of time that the pit will operate, proximity to sensitive areas, local geologic conditions, and other pertinent environmental factors. In addition, the Commission expects that the Director will add appropriate conditions of approval to pit permits under Rule 903 where such conditions are needed to protect public health, welfare, and the environment, considering the listed factors, above. 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 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 unless the Director grants a variance. 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. However, a variance may be appropriate where such a pit would not present such risks because, for example, it only contains produced water. This clarification also provides additional clarity and consistency to Rule 902.e.

Rule 903., PIT PERMITTING/REPORTING REQUIREMENTS Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : The dramatic increase in oil and gas operations in the state, including the use of a wide variety and large number of pits, has led the COGCC to update its approach to regulating, permitting, and tracking pits. Rule 903. addresses the permitting and reporting of pits used for exploration and production of oil and gas. The amendments clarify and simplify the explanation of which pits need to be permitted by the COGCC before they are constructed and which pits may be reported to the COGCC after they are constructed. As under the current Rule, operators use the Earthen Pit Construction Report/Permit, Form 15, for both of these purposes. The Commission understands that the oil and gas industry has developed systems for managing E&P wastes that reduce surface disturbance and oil field traffic, minimize dust, and include waste minimization practices such as the re-use and recycling of drilling and completion fluids. These waste minimization practices are encouraged by COGGC and reduce demand on water resources. If operated in a manner that is protective of public health, safety, and welfare, including the environment and wildlife resources, these practices provide a cost-effective way to produce a needed natural resource.

One such system that has been developed is the use of a pit located at a common point to dispose of produced water from more than one well through evaporation and percolation. These pits reduce surface disturbance and traffic, and allow for cost effective operation of oil and gas wells with marginal production.

Testimony also indicated that multi-well pits have also been employed for the purpose of disposing of water from more than one well. These pits are used during drilling, completion and production and may contain several forms of E&P waste. They also have a limited lifecycle based on the drilling program. A thorough permitting process is necessary to ensure that multi-well pits: are used for either produced water disposal or the storage of fresh water and re-use/recycling of drilling and completion fluids; and are constructed and operated in manner that is protective of public health, safety, and welfare, including the environment and wildlife resources. Before amendment, Rule 903. created a complex process for identifying which pits must be permitted before construction. This process was based on many factors, including the type of pit, pit construction, hydrocarbon and chloride concentrations of drilling fluids, produced water volumes, and sensitive area determination. The Commission amended Rule 903 to eliminate the sensitive area determination requirement and, as a matter of policy, base pit permitting principally on pit type. As amended, the rule requires that all production pits must be permitted. So must special use pits, except for flare pits used when there is no chance of condensate accumulation and emergency pits used during in the initial phase of an emergency response. So must drilling pits where the hydrocarbon concentration exceeds 10,000 parts per million (ppm) or the chloride concentration at total well depth exceeds 15,000 ppm. So must multi-well pits which contain produced water, drilling fluids, or completion fluids that will be recycled or reused, except those pits where reuse consists only of moving drilling fluids from one location to another for reuse there; this will require permitting for multi-well pits that are used for fresh water storage or reuse or recycling of drilling, completion, and frac flow back. The Commission concluded that requiring these categories of pits to be permitted is appropriate because of the potential environmental risks and concerns associated with them. Permitting will provide the COGCC with increased documentation and tracking for these categories of pits. In addition, this will provide an opportunity for COGCC staff to interact with operators to discuss E&P waste management at these sites as well as a means for field inspectors to track operations and closure of these facilities. After considering the record on this issue, the Commission believes that the amendments to Rule 903 strike an appropriate balance between development of oil and gas resources and protection of the environment.

The Commission wishes to emphasize that pits used at a single wellsite where drilling fluids are collected from more than one well for use in drilling and completing the well at that wellsite are not multi-well pits. This is because the purpose of such pits is not storage, treatment or disposal of E&P wastes. Rather, the purpose of the pit is for temporary collection of fluids for immediate use in the drilling of such well. Therefore, such pits do not require a permit pursuant to amended Rule 903.a.(4). Such pits might not need a permit pursuant to amended Rule 903.a.(3) either, if the hydrocarbon or chloride concentration of the fluids in the pits does not meet the threshold in that provision. The Commission also wishes to emphasize that if an operator has a question about what type of pit it is using, it can work with the COGCC staff.

3. Rule 904., PIT LINING REQUIREMENTS AND SPECIFICATIONS Basis : The statutory basis for this rule is section 34-60-106(11)(a)(II). Purpose : The purpose of the pit lining requirements is to minimize public health and environmental impacts from the thousands of waste pits used by oil and gas developers in Colorado to treat, store and dispose of E&P waste.

The Commission heard extensive testimony on the merits of and circumstances under which pits should and should not be lined and adopted a package of lining requirements it believes strikes the appropriate balance between protection of public health and the environment and development of oil and gas resources. More specifically, the Commission adopted a package of requirements that establishes lining requirements that vary with pit contents, pit duration and pit use.

This package of requirements includes a deferral until 2011 of the applicability of pit lining requirements for production pits and for multi-well pits used to contain produced water that will be recycled or reused located in Washington, Logan , Morgan, Yuma, Huerfano and Las Animas Counties. The reason for this deferral is to allow COGCC and CDPHE staff to work with operators and local governments to evaluate further the basis, need and appropriate nature of production pit lining requirements for these Eastern Colorado locations, given the variety of uses for the water, surface and groundwater quality considerations and current oil field liquid waste management practices. As part of this process, operators may seek to demonstrate that production pit percolation in certain areas will not adversely affect surface or ground water, or operators and local governments may seek modification of the applicable surface and ground water standards by the WQCC.

The Commission recognizes there are a variety of pit types, a diversity of pit uses, and that the environment (e.g. surface and groundwater quality) where pits are placed is not the same throughout the state. In view of this, the Commission built certain key flexibilities into the pit lining requirements. These requirements are summarized in the matrix below . The Commission established the regulations in a tiered approach with varying permitting, design, construction, operation, contingency, and closure requirements commensurate with pit service duration, the danger of the wastes/liquids managed in the pits, and the number of operators served by the pits. The regulations are intended to minimize or eliminate the release of E&P waste into the environment, while also protecting human health. In addition, the Commission intends that the regulations define the minimum liner requirements, and the allowable liner design flexibility, for each type of pit. The liner requirements and flexibility were developed to account for site specific conditions, while still being protective of human health and the environment. The regulations define the minimum liner specifications that are acceptable for use at a particular type of pit. They also provide that operators may use alternative liner systems if they demonstrate to the Director’s satisfaction that such alternative systems offer equivalent protection to public health, safety, and welfare, including the environment and wildlife resources. Liner system flexibility was intended to accommodate the inherent natural protectiveness of certain pit locations or alternate engineered liner configurations. For example, consideration may be given for portions of the state where there is a significant distance to groundwater, where a very low permeability layer prevents pit percolation from reaching groundwater , or where alternate engineered and layered configurations of composite liners are used to match the minimum liner protectiveness requirements. The Commission intends that these rules provide that a minimum level of protectiveness is always maintained whether the minimum liner configuration or an alternate design is approved.

These rules as amended by the Commission recognize two major groups of pits: production, drilling, special purpose and multi-well pits , which have a shorter service life; and centralized E&P waste management facility pits , which have a potentially much longer service life and that serve multiple operators. In addition, these rules have been amended to include provisions for new and improved design, construction, operations/monitoring, contingency and closure criteria for all pits.

The Commission adopted liner requirements for all pits that are intended to protect against discharges into, and contamination of, the environment, and to prevent the risk of exposure to contaminants. The minimum liner requirements are more robust for centralized E&P waste management facility pits because of the greater risks these pits pose: centralized E&P waste management facility pits are intended to be used for longer periods of time, to contain larger volumes of fluid, and may be used to manage a wider variety of E&P wastes. Centralized E&P waste management facility pits typically have a service duration commensurate with the production life of the oil/gas field, which may be several decades. These pits service multiple wells rather than an individual well, such that the size of these pits can be significant. More rigorous pit liner requirements for these types of pits are warranted to provide the appropriate level of protection. The Colorado Solid and Hazardous Waste Commission adopted regulations pertaining to Section 17, Commercial Exploration and Production (EP) Waste Impoundments in November, 2008. This section requires liners for pits accepting E&P waste to meet a hydraulic conductivity less than or equal to 1 x 10 -7 cm/sec.

Production pits, other than skim pits (which always need to be lined pursuant to Rule 904.a.(4)), need to be lined unless the operator can demonstrate that the pit will not adversely impact surface water or groundwater. This includes produced water pits , percolation pits , and evaporation pits. The Commission understands that a properly functioning percolation pit cannot be lined. Therefore, for a pit to function as a percolation pit (which requires that it be unlined), the operator will need to demonstrate to the Director’s satisfaction that: (1) the quality of water in the percolation pit is equivalent to, or better than, the underlying groundwater; or (2) that seepage from the percolation pit will not reach groundwater or waters of the state at contamination levels in excess of applicable standards, and then the pit will not need to be lined. If the operator cannot meet either of those requirements, then the pit must be lined and cannot be used for percolation purposes.

4. Rule 905., CLOSURE OF PITS, AND BURIED OR PARTIALLY BURIED PRODUCED WATER VESSELS Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose: Existing Rule 905, authorized an oil and gas operator to leave a synthetic pit liner in place after closure of the pit if the liner was buried on-site and if the landowner had given his/her permission for the on-site burial. As amended, Rule 905 eliminates this authorization. The basis for the Commission’s decision to remove this provision from the rules is that while E&P waste are exempt from solid and hazardous waste requirements, synthetic pit liners are not unique and intrinsic to the oil and gas industry. Therefore, these waste liners are not E&P waste and are, therefore, not exempt from solid waste requirements. Under existing law, all solid waste must be placed into approved and properly permitted solid waste disposal facilities. Closing pit liners in place, even if they are shredded or otherwise breached, represents improper and unpermitted solid waste disposal and cannot, therefore, be allowed. Nonetheless, if the closing pit is being converted to another use, such as a stock watering pond or fresh water storage pond, then the liner has not become a waste and can be left in place until its use for a purpose consistent with its design and intent ceases.

5. Rule 906., SPILLS AND RELEASES Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : This rule deals with all aspects of spills and releases, including required measures to avoid them and actions that must be taken to contain them. Prior to amendment, Rule 906. specified that spills/releases exceeding five barrels, including those contained within unlined berms, had to be reported in writing on a Form 19, Spill/Release Report, but the rule did not require a written report (Form 19) for spills contained within lined berms. Although most operators do submit a written report (Form 19) for spills/releases of this size that are contained in lined berms, not all do. Spills of this size, even if they are contained within a lined berm, still pose a potential threat to public health, safety, welfare, and the environment, including wildlife and surface water resources, and need to be tracked by the COGCC to ensure proper and timely remediation.

Amended Rule 906. also clarifies that all spills/releases exceeding twenty barrels or those of any size that impact or threaten to impact waters of the state, residence or occupied structure, livestock, or public byway, must be: (1) reported verbally to the Director; and (2) reported in writing (Form 19). Although most operators do submit a written report (Form 19), not all do unless a specific request is made by COGCC staff.

The amendments also specify that a topographic map showing the location of the spill/release must be included with the Form 19. Without this amendment, COGCC staff members could not ensure that they were accurately locating the site of the spill/release and were not able to evaluate the potential for a spill/release to impact water resources. Further, the amendments require operators to notify CDPHE about spills/releases that impact or threaten to impact surface waters. In addition, the amendments state that spills and releases that impact or threaten a public drinking water supply intake shall be verbally reported to the emergency contact for that facility immediately after discovery. Prior to the amendments, Rule 906. did not require the operator to notify the surface owner or the owner’s appointed tenant of reportable spills. Although operators frequently do notify the surface owner or the owner’s appointed tenant, not all do. As a result, surface owners and tenants may happen to come upon spills/releases about which they have not been notified. Such surface owners would often contact the COGCC to voice their concerns about impacts from spills/releases and the thoroughness of the remediation activities. This unnecessary aggravation of the surface owner and tenants often could likely have been avoided if the operator had notified them of the incident and its plans for mitigating the impacts and remediating the site, which is why the amended rule requires such notification as soon as practicable and not more than 24 hours after discovery. The amended rule also clarifies that verbal reports to the Director must be made as soon as practicable and not more than 24 hours after discovery. Prior to amendment, Rule 906. did not require containment around tanks containing produced water if the total dissolved solids (TDS) of the water are less than 10,000 mg/l. Spills/releases from storage tanks of produced water, regardless of the TDS of the water, have the potential to impact surface and groundwater unless properly contained and promptly remediated. Therefore, the TDS threshold for secondary containment was changed from 10,000 mg/l to 3,500 mg/l, and additional specifications for secondary containment were added. Collectively, these amendments will improve the COGCC’s ability to track spills/releases and ensure that proper remediation has occurred by clarifying which spills/releases must be reported in writing by the operator and by requiring the inclusion of a topographic map showing the location of the spill. In addition, these amendments will better protect the public and wildlife because when spills/releases are reported, both the COGCC and the operator can use the provided data to analyze the cause of the spills/release and work collaboratively on developing long term strategies for preventing spills/releases from reoccurring in the future. These amendments also protect water resources. Produced water, regardless of the TDS, cannot be allowed to impact surface or groundwater resources. Produced water frequently has a TDS higher than surface water and most shallow groundwater and, if it is produced from reservoirs that contain liquid hydrocarbon or wet-gas, it will contain dissolved hydrocarbon compounds, such as benzene, toluene, ethyl benzene, and xylenes. Therefore, requiring secondary containment around all produced water tanks will result in greater protection to surface and groundwater resources. By requiring operators to notify immediately the operators/emergency contacts of public water supplies with surface water intakes that are threatened by a spill/release, the oil and gas and the water operators can work together jointly to ensure all necessary precautions are taken to protect water users and to remediate any impacts promptly.

6. Rule 907., MANAGEMENT OF E&P WASTE Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : This rule deals with the proper management of E&P waste. Within the last several years, mismanagement of drilling fluids and non-incorporation of the fluids when used as a soil amendment has resulted in at least eleven incidents in the Greater Wattenberg Area of Weld County. Mismanagement issues included excessive loading of drilling mud at several locations resulting in offsite migration of fluids. Six of these drilling mud incidents impacted surface water including the Cache La Poudre River. Laboratory results of a drilling mud sample collected at one of these incident sites indicated residual petroleum hydrocarbons. This amendment should result in enhanced E&P waste management practices by industry and thereby reduce environmental impacts. For instance, the new requirement that drying and burial of drilling fluids in drilling pits on non-crop land with the resulting concentrations required to not exceed the allowable concentrations and levels in Table 910-1 will be more protective of the environment. Similarly, the clarification to the reuse and recycling requirements will help ensure that the Director receives appropriate information to review proposed waste management plans, and the clarifications to the waste generator requirement will help the COGCC to track waste transportation. The management practices required by this amendment better balance the development of oil and gas resources with protection of the environment. Faster incorporation of drilling mud into soils when used as a beneficial amendment will result in less potential for offsite migration into surface waters.

The Commission also amended Rule 907.c to reduce from 5,000 mg/l to 3,500 mg/l the allowable TDS concentration in produced water used for road dust suppression. The Commission made this change after considering testimony from the CDPHE and several parties. Specifically, the Commission learned that some operators dispose of produced water on roads in excess of amounts needed to suppress dust. The CDPHE suggested that some operators also apply produced water for dust suppression during rain events, suggesting that operators are simply "dumping" the produced water. Testimony also indicated that water with TDS concentrations above 3,500 mg/l can have detrimental effects on livestock that drink it, which is why the state water quality standard for agricultural/livestock use is 3,500 mg/l. The Commission also learned that watering roads with TDS concentrations in the 3,500 mg/l and higher ranges can actually increase road dust over time due to the interaction of TDS in the water with road material. However, the Commission also heard testimony from certain local government parties expressing a desire to keep the limit at 5,000 mg/l TDS because lowering it could reduce the amount of available water for dust suppression.

Balancing all the testimony it received on this issue, the Commission decided that the COGCC limit should be consistent with the state water quality standard for agricultural/livestock use. While the Commission believes this to be the appropriate TDS threshold for the reasons stated above, it also requests staff to work with CDPHE and those Counties desiring to use produced water for dust suppression. The Commission anticipates an update from staff or CDPHE by the end of the calendar year 2010.

Rule 907.f., Other E& P Wastes, outlines acceptable waste disposal practices for wastes from natural gas plant sweetening and dehydration, pipeline pigging, tank bottoms and work over fluids. These wastes have shown greater likelihood to be toxic. To ensure public health, safety, and welfare, including the environment and wildlife resources, additional controls and overview is required for these wastes. Under Rule 907.f., onsite land treatment and landfarming for these types of wastes (unless at a permitted commercial facility or centralized waste management facility) will not be allowed unless approved by the Director.

7. Rule 908., CENTRALIZED E&P WASTE MANAGEMENT FACILITIES Basis : The statutory basis for the amendments to this entire rule is section 34-60-106(11)(a)(II), C.R.S.

Purpose : Rule 908 addresses the regulation of centralized E&P waste management facilities. The amendments update and revise a number of these regulatory requirements, including those for design, operation, monitoring, emergency planning, financial assurance, and closure. As a matter of policy, the Commission concluded that the amendments are appropriate because they will help ensure that such facilities properly protect public health and the environment. The amendments will also make the COGCC requirements more consistent with the CDPHE requirements for commercial E&P waste management facilities, which often have similar environmental issues. The Commission determined that although these amendments will impose some additional expense and burden on the industry, they strike an appropriate balance and are reasonable under the current circumstances.

a. Rule 908.b., Permit requirements Rule 908.b.(7) pertains to facility design and engineering. The amendments will require the submittal of more comprehensive information regarding the site characteristics, including geologic and hydrologic data. This additional information is intended to assist the COGCC staff in reviewing and evaluating permit applications and in developing appropriate conditions to protect public health and the environment. Rule 908.b.(8) deals with operating plans. The amendments include a requirement that such plans address noise and odor mitigation. This requirement is intended to avoid or minimize noise and odor complaints and better protect the public welfare. Rule 908.b.(9) addresses groundwater monitoring. The amendments set forth detailed water well sampling and analysis criteria. They also require operators to make good faith efforts to identify and obtain access to water wells known to the operator or registered with the State Engineer for sampling purposes and clarify what happens if access is denied. The Commission believes that these amendments provide important additional protection for public health, safety, and welfare, including the environment and wildlife resources.

1. The amendments also add Rules 908.b.(10) and (11). Subsection (10) requires surface water monitoring under certain circumstances. The Commission believes that this addition will better protect surface water quality. Subsection (11) requires a contingency plan that includes emergency response and contact information. The Commission believes that this addition will better protect public health and the environment.

b. Rule 908.d., Financial assurance Rule 908.d. was amended to clarify that the financial requirement applies to all centralized E&P waste management facilities and not just land treatment facilities and that such financial assurance must be submitted before the operating permit is issued.

c. Rule 908.f., Annual permit review Rule 908.f. was amended to require submittal of an annual report by the operator that includes the types and volumes of waste handled at the facility. Such information could then be verified by COGCC staff if necessary, and it will keep the COGCC better informed on the facility’s operations.

d. Rule 908.g., Closure Rule 908.g. was amended to specify certain information that must be included in the preliminary and final closure plans to help ensure proper protection of public health and the environment. Prior to amendment, a closure plan was required to be submitted, but there was no guidance as to what information was required. The requirement that the operator provide cost estimate information is intended to help ensure that the necessary funding will be available to close and reclaim the facility. The references to collecting samples as needed are intended to reflect that the collection of soil and groundwater samples will be governed by Rule 910.b, and that such samples may not be required in all circumstances.

e. Rule 908.h., regarding local requirements Local governments and other agencies impose their own requirements on these facilities. Prior to amendment, Rule 908.h. simply stated that operators needed to provide the Director with copies of notifications to local governments or other agencies. As amended, Rule 908.h requires that operators provide verification of approval from these other entities prior to COGCC approval. This will ensure that operators are in compliance with all necessary regulatory requirements.

8. Rule 909., SITE INVESTIGATION, REMEDIATION AND CLOSURE Basis : The statutory basis for the amendments to this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose : Rule 909 applies to: the closure and remediation of pits other than drilling pits; the investigation, 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. Only minor, conforming amendments were made to this rule.

9. Rule 910., ALLOWABLE CONCENTRATIONS AND SAMPLING FOR SOIL AND GROUNDWATER Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : Rule 910. addresses the cleanup standards for groundwater and soils impacted by E&P wastes. Table 910-1 was substantially amended to make the soil standards consistent with those used by CDPHE – Hazardous Materials and Waste Management Division for clean up of impacts to soil from similar materials and reflect the most current toxicological information and analysis. In addition, language was added to Table 910-1 clarifying that consideration will be given to background levels in native soils and groundwater, and other language was added to the rule clarifying that analytical parameters will be selected based on site-specific conditions and process knowledge and must be approved by the Director. Prior to these amendments, the standards for the remediation of impacted soils used by the COGCC for oil and gas operations were different than those used by CDPHE – Hazardous Materials and Waste Management Division. Now, consistent standards are applied. The rapid spread of rural residential development and expansion of urban areas contributes to changes in land use from agricultural, rangeland, and forest to residential and commercial. Current soil cleanup standards that were adequate for the original use may not be protective of the new and future uses, necessitating this amendment.

In addition, prior to this amendment, the COGCC’s cleanup standards for soils were not definitively protective enough of groundwater quality by limiting leaching potential. The COGCC is the implementing agency for groundwater standards and classifications set by CDPHE – Water Quality Control Commission. The amendments pertaining to cleanup standards for groundwater are those set by the WQCC; these amendments do not change those groundwater standards. The new standards are beneficial to the public welfare because they allow for unrestricted future use of the property and are protective of water quality. The amendments provide a greater incentive for operators to prevent spills and releases and to remediate them in a timely manner. Rapid response and remediation will minimize the volume of waste that the operator must treat or remove for disposal, reduce the potential for exposure of the public and wildlife, and reduce the risk of impacting ground and surface water resources. Table 910-1 As amended, Table 910-1 establishes new soil and groundwater cleanup standards for oil and gas operations. The Commission set the allowable concentrations presented in the table at levels to assure that contamination clean up efforts by operators are sufficient to allow remediated property to be available for unrestricted future use. More specifically, the standards facilitate protective cleanups without long-term liabilities or responsibilities to the oil and gas operators and no potential for unacceptable risks affecting public health or the environment. After receiving extensive comment addressing a variety of perspectives on the merits of establishing appropriate soil and groundwater cleanup standards, the Commission decided that amended Table 910-1 represented a balanced and fair approach to allowing oil and gas development to occur while protecting public health and the environment.

The Commission also deliberated on the merits of removing from the rules a seldom used provision that authorized operators to seek permission from the Director to undertake “risk-based” cleanups. In reaching its decision, the Commission reasoned that while “risk-based” cleanup approaches can allow higher levels of contamination to be left behind at a contaminated site, and can thus be a less expensive clean-up option, they likely could result in the need to place limitations on how that land can be used in the future. Accounting for the fact that a large percentage of Colorado’s oil and gas development activity occurs on lands not owned by the oil and gas operators, and on lands where residential, agricultural and/or commercial uses occur in close proximity to the oil and gas development, the Commission, after weighing the evidence, decided that “risk based” cleanups are not currently appropriate because of the potential for future exposure to the contaminant that might be left onsite. Risk-based cleanups rely heavily on risk assessments to calculate the risk presented to the public and to the environment from exposure to the contamination under various future scenarios. These risk assessments are complex and resource intensive, and they require specialized toxicological and risk assessment experience. The COGCC does not have the resources needed to conduct such risk assessment evaluations. In addition, the Commission does not have independent statutory authority to impose and enforce land use controls in the form of “environmental covenants” that must accompany cleanups to restrict future uses where remaining contamination could be dangerous. Absent this authority there would be no effective means for assuring that future uses of the contaminated site would remain restricted to prevent exposure to the harmful levels of contaminants remaining onsite.

In the future if the COGCC obtains the required statutory authority and resources, the Commission could revisit this issue and amend these rules to include less restrictive cleanup standards in Table 910-1 and/or a risk-based evaluation process that industry could use to justify alternative cleanup standards. For the time being the Commission has decided that as a matter of policy, the public health and environmental protection approach reflected in Table 910-1 is most appropriate.

As with all of the COGCC rules, an operator may seek a variance from the provisions of Rule 910 or the concentration levels in Rule 910-1, pursuant to Rule 502.b, under appropriate circumstances. The Commission also notes that the future closure and remediation of pits existing on or after May 1, 2009 on federal land or on or after April 1, 2009 on all other land will be subject to the concentration levels of Table 910-1, as amended.

10. 911., BURIED OR PARTIALLY BURIED PRODUCED WATER VESSEL, BLOWDOWN PIT, AND BASIC SEDIMENT/TANK BOTTOM PIT MANAGEMENT REQUIREMENTS PRIOR TO DECEMBER 30, 1997 Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : Rule 911. addresses the management, operation, closure, and remediation requirements for certain pits that were constructed more than a decade ago. The rule was amended by the addition of the following language: “In December, 2008, Figure 901-1 was deleted from the 900-Series Rules.” This amendment is consistent with the amendments to Rule 901, which eliminate the Sensitive Area Determination Decision Tree.

11. Rule 912., VENTING OR FLARING NATURAL GAS Basis : The statutory basis for this rule is section 34-60-106(11)(a)(II), C.R.S. Purpose : This rule addresses the venting or flaring of natural gas. Flaring is used as a means of converting natural gas constituents into less hazardous and atmospherically reactive compounds. Depending on the composition of the natural gas, the venting process may release hydrocarbons other than methane, such as ethane, propane, butane, pentane and hexane, into the atmosphere. Natural gas may also contain the EPA-designated Hazardous Air Pollutants (HAPs) benzene, toluene, ethyl benzene and xylenes (BTEX). HAPS can account for 0.3 - 0.6 % of the natural gas composition. Depending on the formation, natural gas may also contain nitrogen, carbon dioxide or sulfur compounds, such as hydrogen sulfide (H S).

The amendments to this rule require that under certain circumstances flared gas be directed to a controlled flare or other combustion device operated as efficiently as possible to provide maximum reduction of air contaminates where practicable and without endangering the safety of well site personnel and the public. This will reduce the amount of HAPS and other hydrocarbons released into the atmosphere and thereby help protect public health, safety, and welfare. Additions to the 900-Series The following Rule 907A. was added:

Rule 907A., MANAGEMENT OF NON-E&P WASTE Basis : The statutory basis for this rule is section 34-60-106(11)(a)(II). Purpose : The purpose of new Rule 907A is to clarify how different oil and gas development waste is defined and by whom it is regulated. These provisions address confusion that can surround the definition of “E&P waste” . More specifically, many wastes generated in the normal course of oil and gas exploration and production are not considered E&P wastes and are, therefore, subject to state and federal solid and hazardous waste regulations administered by CDPHE and EPA. The Commission believes this clarification will facilitate the proper handling and disposal of such waste.

1000-Series Reclamation Regulations Amendments to the 1000-Series The following rules were amended:

1. Rule 1001., INTRODUCTION Basis : The statutory bases for the amendments to this Rule are sections 34-60-106(11)(a)(II) and 34-60-128(3)(d), C.R.S.

Purpose : Rule 1001.c was amended to provide that compliance with Rules 1002.e.(1) & (4), 1002.f, and 1004.c.(4) & (5) will still be required even if the operator has entered into an agreement with the surface owner regarding topsoil protection and reclamation of the land. This is because the rules in question do not involve reclamation standards or objectives, but minimization of dust and erosion (Rule 1001.e.(1)), construction and use of access roads (Rule 1001.e.(4)), management of stormwater (Rule 1002.f), notice of final reclamation (Rule 1004.c. (4)), and inspection of final reclamation (Rule 1004.c.(5)). The Commission concluded that continued compliance with these rules should not restrict future land use or interfere with the surface owner’s rights.

2. Rule 1002., SITE PREPARATION AND STABILIZATION (formerly SITE PREPARATION) Basis : The statutory bases for the amendments to this Rule are sections 34-60-106(11)(a)(II) and 34-60-128(3)(d), C.R.S.

Purpose : The purpose of these amendments is to ensure proper site preparation and stabilization. Accordingly, Rule 1002.’s title was expanded from site preparation to site preparation and stabilization.

a. Rule 1002., all subsections except 1002.f.

1. Except for subsection f., most of the amendments to Rule 1002 primarily pertain to soil removal and segregation and should simplify site preparation and enhance reclamation efforts. The USDA - Natural Resources Conservation Service no longer uses the A, B, and C soil horizon nomenclature, but instead directs that, “topsoil” should be used to cover an area so that vegetation can be established and maintained. Surface soil layers are generally preferred for topsoil because of the organic matter, which increases the absorption and retention of moisture and nutrients and improves the growth of plants. Therefore, the amendments eliminate references to the A, B, and C soil horizons and require that topsoil be segregated on non-crop land. This should add clarity and facilitate faster reclamation.

   The amendments also call for improved methods of site preparation, which should aid in interim and final reclamation. For example, the amendments require operators to reduce adverse impacts on wildlife resources by using directional drilling where feasible and to avoid or minimize wetland and riparian impacts and consolidate facilities and rights-of- way to the extent practicable. The Commission concluded that these are reasonable requirements that properly balance oil and gas development with protection of the environment and wildlife resources consistent with HBs 07-1298 and 07-1341.

b. Rule 1002.f., Stormwater management The Commission added this rule to include requirements for developing and implementing stormwater management plans for most ongoing operations of oil and gas production facilities.

1. The amended rule applies to the post –construction operation of oil and gas producing facilities. It requires all oil and gas locations to employ BMPs that are tailored to reflect local conditions. Stormwater controls for protecting water quality during the construction of a facility are addressed separately in the CDPHE/Colorado Water Quality Control Division’s (“WQCD” ) stormwater permitting requirements in the Colorado Discharge Permit System Regulations (5 CCR 1002-61).

   The Commission recognizes that some oil and gas locations have certain characteristics that do not warrant development of a stormwater management plan. They include those with a the slope of less than 5 %, vegetative cover or permanent erosion resistant cover greater than 75%, a distance from a perennial stream or Classified Water Supply Segment greater than 500 feet, a location size less than one acre, measured by the amount of surface disturbance at the time of the termination of a construction stormwater permit issued by CDPHE and soil with low erosion potential. While all soils have the ability to erode, soils with both a high percentage of clay and little or no silt content are generally considered to have low erosion potential. An example of an oil and gas location with these characteristics could include a cultivated field. The amended rule provisions are not intended to be as rigorous as those for stormwater management plans required under stormwater construction permits issued by the CDPHE/WQCD. For instance, the stormwater plan under these rule amendments must be site-specific only to the extent necessary to describe implementation where general operating procedures and descriptions are not adequate to clearly describe the implementation and operation of BMPs. Furthermore, stormwater management plans are not required at locations where soil erosion potential is low, vegetative cover is high, disturbed land is less than an acre, and slope is less than 5%. Also, the amended rule does not identify a specific inspection schedule, but leaves it to the operator to determine the inspection schedule appropriate for the particular location. Based on the evidence in the hearing record, the Commission decided that these rule amendments are necessary because they fill a regulatory gap that would otherwise allow storm and non-storm related discharges from oil and gas operations, including pollutants such as sediment from roads/pads and chemicals associated with an oil and gas production site or associated support facilities. Prior to this amendment, such discharges were not regulated. The amended rule requires operators to employ “common sense” /good engineering approaches to prevent run-on and run-off from oil and gas locations and associated roads from entering surface waters. Significantly, these requirements are consistent with those included in stormwater permits required for ongoing operation in other industrial sectors, such as metals mining.

   Rule 1002.f. sets forth the general requirements that balance protection of the environment with development of oil and gas resources. Requirements include those for implementing BMPs, without attempting to specify which BMPs are required in the widely varying site-specific circumstances encountered at oil and gas locations. The intent is to identify the categories of BMPs that need to be addressed, while preserving flexibility for the operator to exercise site-specific judgment as to the specific BMPs applied. The Commission recognizes that the flexibility provided by this approach requires operators to exercise judgment and does not provide certainty as to what is required at each operational location. Many factors may affect decisions on which and to what degree BMPs may be appropriate at particular locations, including but not necessarily limited to, topographic relief, soil erosion potential, presence of vegetative or other erosion-resistant cover, facility size, local hydrology, and the nature of the materials used at the site. Many forms of guidance documents regarding the selection of stormwater BMPs are available and the Commission encourages oil and gas operators to rely on them when selecting appropriate BMPs. Examples that provide useful tools for selecting BMPs include, but are not limited to:

   - BMP manuals such as Urban Drainage and Flood Control District’s Volume III (www.udfcd.org/downloads/down_critmanual.htm) and CDOT’s BMP manual ( http://www.dot.state.co.us/Environmental/envWaterQual/wqms4.asp ) - Guidelines in BLM’s Oil and Gas Exploration and Development Gold Book - Civil engineering design manuals for roads, drainage, culverts, etc., which specify appropriate design specification for stable infrastructure. In addition, the Commission encourages staff to consider developing additional informational guidance following the finalization of this rule, which may help operators identify additional useful reference material and select effective site specific BMPs. The Commission notes that the appropriate timing of stormwater BMP inspections will vary with site-specific circumstances. For example, inspection frequency generally does not need to be as frequent during a stable operational phase as during a construction period where more surface disturbance is occurring. The factors listed above will also be relevant in determining inspection frequency, determined by the operator. This rule is not intended to hold oil and gas operators responsible for minimizing or controlling discharges to state waters of sediment from natural erosion that occurs beyond the oil and gas location. Operators will, however, be responsible for implementing and maintaining BMPs to control pollutant sources associated with oil and gas operations, even when BMPs may be impacted by off-site pollution sources, including sediment from natural erosion.

   The Commission intends that the standard applied by staff in overseeing and enforcing implementation of these stormwater requirements be one of reasonableness. Recognizing that considerable site-specific judgment is required, the Commission expects staff to apply the test of whether the operator has exercised a good faith effort to implement BMPs intended to serve the purposes of this rule. Where appropriate and desired by the operator, staff can and should work with an operator to identify additional BMPs that may be appropriate at a particular facility.

   Rule 1002.f. is not intended to be seen as overlapping with the CDPHE/WQCD stormwater permitting requirements, referenced above. Once an oil and gas facility has achieved final stabilization and a CDPHE stormwater construction permit is no longer required, the operator must inactivate the stormwater permit coverage. CDPHE issues field permit certifications that allow multiple oil and gas facilities to be covered under the same certification. These field permit certifications cover CDPHE-regulated construction activities within a specific geographical area, as identified in an oil and gas facility’s stormwater management plan. The Commission understands from CDPHE that prior to the effective date of this Rule, CDPHE will implement measures to allow for inactivation of portions of permit coverage for specific facilities/areas covered under a field permit certification. Once the CDPHE stormwater permit is inactivated for a specific location the stormwater requirements under this new rule will become effective for that location.

3. Rule 1003., INTERIM RECLAMATION Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II) and 34-60- 128(3)(d), C.R.S.

Purpose : Rule 1003. pertains to interim reclamation. The amendments to Rule 1003. provide for more effective interim reclamation, which will result in less potential for erosion and potentially faster restoration of wildlife habitat consistent with HB 07-1298. As a matter of policy, the Commission concluded that these amendments are appropriate as an initial package of measures to improve the interim reclamation of wildlife habitat. However, the Commission directed the COGCC staff to convene a stakeholder process during the first quarter of 2009 to discuss and attempt to develop consensus on additional and more extensive regulatory amendments to better ensure the timely and appropriate interim and final reclamation of wildlife habitat. Based upon the outcome of the stakeholder process, the Commission may initiate a subsequent rulemaking proceeding during 2009 to further address this issue.

a. Rule 1003.a. – General Rule 1003.a. was amended to delete language that allowed material to be burned or buried on site under certain circumstances. Burning of material at a site would require a permit from the local government or the Air Pollution Control Division of the CDPHE. Burial of material would violate the Regulations Pertaining to Solid Waste Sites and Facilities of the Hazardous Materials and Waste Management Division of the CDPHE unless prior approval were received.

1. Rule 1003.a. was also amended to clarify that all wellsites and surface production facilities shall be maintained in accordance with Rule 603.j. As a matter of policy, the Commission chose to occasionally cross-reference rules to ensure compliance with all relevant rules.

b. Rule 1003.b. – Interim reclamation of areas no longer in use Prior to amendment, Rule 1003.b. allowed operators up to twelve months to perform interim reclamation on non-cropland for areas no longer in use. That provided a long window of time for erosion to occur and for noxious weeds to grow. This twelve-month period was decreased to six months, which better protects the environment by reducing the potential for erosion and noxious weed growth. Rule 1003.b. was also amended to require areas reasonably needed for production operations to be stabilized to control dust and minimize erosion to the extent practicable. This language reflects the Commission’s belief that erosion is a natural process that cannot be entirely avoided.

c. Rule 1003.d. –Drilling pit closure Rule 1003.d was amended to add a requirement that operators ensure that soils in drilling pits meet the standards set forth in Table 910-1. Additionally, the amendments specify that operators must close and reclaim drilling pits no later than three months after drilling and completion activities conclude on crop land and no later than six months after such activities conclude on non-crop land. These amendments intended to ensure more timely interim reclamation.

d. Rule 1003.e. – Restoration and vegetation Rule 1003.e was amended to add a performance standard for interim reclamation. Under this standard, interim reclamation is considered complete when: all disturbed areas have been either built on, compacted, covered, paved, or otherwise stabilized 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 plant cover of at least 80% of pre-disturbance or reference area levels, excluding noxious weeds. Reseeding alone is not sufficient. The Commission’s adoption of this standard reflects a policy decision based evidence in the hearing record and the mandate of HB 07-1298. CDOW staff and conservation group parties testified that an 80% standard is achievable and protective of wildlife resources. Although the Commission understands that certain other regulatory programs use a 70% standard, it notes that the programs in question are not directed to the proper reclamation of wildlife habitat and that other regulatory programs do use an 80% standard. Nor should complying with a 70% standard for other purposes prevent or obstruct an operator from complying with an 80% standard for reclamation. Therefore, after considering wide-ranging input on this issue, the Commission concluded that the standard adopted will best ensure proper reclamation of wildlife habitat as contemplated by HB 07-1298.

1. Rule 1003.e was also amended to clarify that disturbed areas must be reseeded in the first favorable season following rig demobilization, and to add a requirement that operators submit an interim reclamation completion notice with photographic evidence of reclamation success. This notice is intended to assist the COGCC staff in monitoring interim reclamation and ensuring that such reclamation is completed in a timely manner.

e. Rule 1003.f. – Weed control Prior to amendment, Rule 1003.f. stated that all disturbed areas shall be kept “reasonably” free of noxious weeds. That term was ambiguous and made it hard for the COGCC to enforce that rule. As amended, Rule 1003.f. provides better guidance to operators in controlling noxious weeds and authorizes the Director to require a weed control plan. For instance, the rule now specifies that weed control measures must comply with the Colorado Noxious Weed Act and its implementing regulations, recommends that operators consult with local authorities to assure proper weed control, and requires operators to monitor disturbed areas and reclaimed sites for noxious weed infestations. The Commission believes that these amendments are appropriate and will further interim reclamation efforts.

4. Rule 1004., FINAL RECLAMATION OF WELL SITES AND ASSOCIATED PRODUCTION FACILITIES Basis : The statutory bases for this amendment are sections 34-60-106(11)(a)(II) and 34-60- 128(3)(d), C.R.S.

Purpose: Rule 1004. pertains to final reclamation. The amendments to Rule 1004. provide for more effective final reclamation, which will result in less potential for erosion and potentially faster restoration of wildlife habitat consistent with HB 07-1298. As a matter of policy, the Commission concluded that these amendments are appropriate as an initial package of measures to improve the final reclamation of wildlife habitat. However, as noted above, the Commission has directed the COGCC staff to convene a stakeholder process during the first quarter of 2009 to discuss and attempt to develop consensus on additional and more extensive regulatory amendments to better ensure the timely and appropriate interim and final reclamation of wildlife habitat. Based upon the outcome of the stakeholder process, the Commission may initiate a subsequent rulemaking proceeding during 2009 to further address this issue.

a. Rule 1004.a. – Well sites and associated production facilities Rule 1004.a. was amended to delete language that broadly allowed material to be burned or buried on site . In its place, language was added to clarify that any such burning or burial must comply with applicable local, state, or federal solid waste disposal regulations, must satisfy the 900 Series Rules, and must be authorized in writing by the surface owner. Language was also added to specify that equipment, supplies, weeds, rubbish, and other waste material must be removed from the site. These amendments are intended to clarify final reclamation requirements and thereby further final reclamation efforts.

b. Rule 1004.c. - Final reclamation threshold for release of financial assurance Rule 1004.c. was amended to specify that on non-crop land, final reclamation is considered complete when: all disturbed areas have been either built on, compacted, covered, paved, or otherwise stabilized 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 plant cover of at least 80% of pre-disturbance or reference area levels, excluding noxious weeds. The Commission’s reasoning in adopting this amendment is the same as that set forth above under amended Rule 1003.e. The amendments also specify that the final reclamation notice must describe any changes in the landowner’s designated final land use.

c. Rule 1004.d – Untitled Rule 1004.d was added to provide a performance standard for final reclamation. Under this standard, final reclamation, like interim reclamation, is considered complete when: all disturbed areas have been either built on, compacted, covered, paved, or otherwise stabilized 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 plant cover of at least 80% of pre-disturbance or reference area levels, excluding noxious weeds. Reseeding alone is not sufficient. The Commission’s reasoning in adopting this standard is the same as that set forth above for adoption of the interim reclamation standard under amended Rule 1003.e.

d. Rule 1004.e. – Weed control Rule 1004.e was added to impose weed control requirements on areas undergoing final reclamation identical to the requirements that apply to areas during drilling, production, and interim reclamation under amended Rule 1003.f. The Commission believes that this addition is appropriate and will further final reclamation efforts. Additions to the 1000-Series There were no additions to the 1000-Series of rules.

1100-Series Pipeline Regulations Amendments to the 1100-Series The following rules were amended:

1. Rule 1101., INSTALLATION AND RECLAMATION Basis : The basis for this amendment is COGCC Order No. 1R-103. Purpose : Rule 1101 was amended to reflect rulemaking action by the Commission on September 18, 2006, to delete Rule 1101.a, see Order No. 1R-103, and to bring the Secretary of State’s rules in conformance with the Commission’s rules and rulemaking actions. The Commission’s September 18, 2006 rulemaking deleted Rule 1101.a and redesignated Rules 1101.b through 1101.f as Rules 1101.a through 1101.e. The Commission previously stated the purpose for that rulemaking as follows:

“On March 15, 2006 (after the Commission promulgated amendments to the 100- and 1100- Series Rules on October 31, 2005) the U.S. Department of Transportation, Office of Pipeline Safety (USDOT), revised its definition of gathering lines and outlined a new process to determine which lines are subject to its minimum safety standards. The Colorado Public Utilities Commission (CPUC) is responsible for enforcing federal pipeline safety regulations in this state and will be promulgating rules to comport with the federal program. “There is duplication and conflict between the Commission’s 100 and 1100 Series Rules and the March 15, 2006 rules promulgated by USDOT primarily because of the definition of “gathering lines” by each agency. Therefore, there is likely to be duplication and conflict between the Commission’s 100 and 1100 Series Rules with rules promulgated by CPUC to implement the federal program.

“The Commission wants to rescind rules that may duplicate or conflict with CPUC’s rules. The Commission considered alternatives to rescinding its rules that apply to “gathering lines,” including suspending their effectiveness until the CPUC promulgates its rules. However, due to the length of time anticipated for the stakeholder process, public comment, and drafting proposed rules, the Commission determined it was more efficient to rescind its rules as they apply to “gathering lines” until such time and the CPUC delineates those pipelines that are subject to its jurisdiction.”

2. Rule 1102., OPERATIONS, MAINTENANCE, AND REPAIR Basis : The statutory basis for this amendment is section 34-60-106(11)(a)(II), C.R.S. Purpose : Rule 1102 was amended to require operators of pipelines over which the COGCC has jurisdiction to become a member of the Utility Notification Center of Colorado (“UNCC” ) and to participate in Colorado’s One Call notification system. The primary purpose of the UNCC is to act as a messaging center for Colorado between excavators and underground facility operators to locate requests when excavation activity is needed and to educate the industry and general public on the Colorado One-Call notification system.

The requirements of Colorado’s One-Call notification system are codified at sections 9-1.5-101 et seq , C.R.S. The purpose of the system is to prevent injury to persons and damage to property from accidents resulting from damage to underground facilities, including those used for the storage or conveyance of oil and gas, by excavation. This purpose is facilitated through the creation of a single statewide notification system that is administered by an association of the owners and operators of underground facilities. Through the association, excavators are able to obtain crucial information regarding the location of underground facilities prior to excavating and are thereby able to greatly reduce the likelihood of damage to any such underground facility or injury to any person working at an excavation site.

The addition of these requirements will allow operators and other interested parties to work together to: (1) reduce damage to underground facilities; (2) promote safe digging practices; and (3) promote the use of the one-call system. As a result, these additions will ensure better protection of public health, safety, and welfare, including protection of the environment. Prior to the amendment, Rule 1102. required participation in Colorado’s One-Call notification system but did not specifically mention what association administers the program. This association is the UNCC. This amendment was necessary because a recent audit of active oil and gas operators identified several hundred companies that are not UNCC members. Additions to the 1100-Series There were no additions to the 1100-Series of rules.

1200-Series Protection of Wildlife Resources The adoption of the 1200-Series Rules is intended to implement the legislative declaration stated in HB 07-1298 to “plan and manage oil and gas operations in a manner that balances development with wildlife conservation in recognition of the state’s obligation to protect wildlife resources and the hunting, fishing, and recreational traditions they support, which are an important part of Colorado’s economy and culture.” See §33-60-102(1)(a)(IV), C.R.S. The Commission has been mindful throughout the current rulemaking process of its obligation to address those competing interests by adopting regulations that provide an appropriate balance and will responsibly “minimize the adverse impacts to wildlife resources” affected by oil and gas operations. See §33-60-128(3)(d), C.R.S.

In considering and choosing between the various regulatory proposals that have been presented throughout this proceeding, including those by the COGCC staff, the industry parties, the environmental parties and wildlife groups, local governments, and representatives of Colorado agriculture and surface owners, the Commission made policy choices that it believes will minimize adverse impacts to wildlife resources where reasonably practicable and taking into consideration cost effectiveness and technical feasibility while also maintaining an appropriate balance between development of state oil and gas resources and conservation of state wildlife resources.

Additions of the 1200-Series The following rules were added to comprise the 1200-Series:

1. Rule 1201. – IDENTIFICATION OF WILDLIFE SPECIES AND HABITATS Basis : The statutory basis for this Rule is section 34-60-128(3)(d), C.R.S. Purpose : In order to administer the Act and the COGCC regulations in a way that minimizes adverse impacts to wildlife resources, the COGCC must first know which wildlife resources could be impacted by oil and gas development activities. The Commission heard numerous proposals to accomplish this, and it initially considered a proposal that would have required operators to conduct site surveys for wildlife species and habitat types. This approach raised issues as to whether such a site-specific survey requirement would place an unnecessary burden on oil and gas operators and whether it would lead to public disclosure of information property owners would prefer to keep confidential.

After hearing testimony from a wide range of interests and conducting deliberations, the Commission determined as a matter of policy that the most appropriate mechanism for identifying wildlife species and habitats was to require operators to review information already produced and maintained by the DOW as part of its statewide wildlife management activities. The CDOW has and maintains a statewide classification and mapping system that identifies such “restricted surface occupancy areas” and “sensitive wildlife habitats” throughout Colorado. The definitions for “restricted surface occupancy areas” and “sensitive wildlife habitats” provide that the extent of these areas may be subject to periodic update and may be modified only through the Commission’s rulemaking process as provided in Rule 529. If conditions warrant, the CDOW may come forward with a request for rulemaking to change the “restricted surface occupancy areas” and “sensitive wildlife habitats” maps. Also, the Commission believes that if serious issues arise affecting the continued viability or the listing of a species under the Endangered Species Act, then the CDOW may request that the Commission amend the “restricted surface occupancy areas” and “sensitive wildlife habitats” maps through a rulemaking. Rule 1201 requires operators to review maps and special data maintained on the COGCC website and maps attached as Appendices VII and VIII to the COGCC rules of sensitive wildlife habitat and restricted surface occupancy areas to determine whether a proposed oil and gas location is within an area identified by one of these two maps. This information will be maintained in a format and at a scale that can be used by operators to complete the identification requirement stated in Rule 1201. This determination is to be made prior to preparation of a Comprehensive Drilling Plan or submittal of a Form 2A.

Once such review is completed, the operator is required to include the location of and information on restricted surface occupancy areas and sensitive wildlife habitats as part of the Form 2A or Comprehensive Drilling Plan. The determination of whether the proposed oil and gas location is within a restricted surface occupancy area or area of sensitive wildlife habitat will be used to determine whether the requirements of Rules 1203. and 1205. apply to the proposed oil and gas location and are the primary basis for a consultation, if necessary, under Rules 306 and 1202.

2. Rule 1202. - CONSULTATION Basis : The statutory basis for this Rule is section 34-60-128(3)(d), C.R.S. Purpose: HB 07-1298 specifically recognized the importance of consultation with the CDOW in minimizing adverse impacts to wildlife resources affected by oil and gas operations. See §34-60- 128(3)(d)(I), C.R.S. Accordingly, the COGCC has incorporated such a consultation process with the CDOW into its regulatory scheme. It is the intent of the Commission that such consultation will ensure that permitting decisions reflect an appropriate balance between development of oil and gas resources and minimization of adverse impacts on wildlife resources through a discussion of the issues involving the COGCC, the CDOW, the operator, and the surface owner. The Commission believes this consultation process provides the most appropriate mechanism whereby the Director of the COGCC can determine whether conditions of approval are necessary to minimize adverse impacts from proposed oil and gas operations in sensitive wildlife habitat or, where allowed, restricted surface occupancy areas . It is also the intent of the Commission that this consultation will provide the appropriate mechanism for the Director of the COGCC to determine whether variances from other provisions in the 1200-Series, including Rules 1203., 1204., and 1205., can be granted while still ensuring that adverse impacts to wildlife resources are minimized.

Other regulatory proposals were presented to the COGCC for incorporation into its consultation process, including the establishment of baseline restrictions, such as timing limitations, that would apply in particular wildlife habitats unless otherwise waived or modified as part of the consultation process. After considering a wide range of testimony by staff, the parties, and the public on this issue, the Commission concluded as a matter of policy that a case-by-case evaluation and discussion without imposing any unnecessary sidebars to that discussion, such as timing limitations, is a more appropriate mechanism to ensure that the interests of all parties are appropriately taken into consideration and that the Director is able to achieve an appropriate balance between oil and gas development and conservation of wildlife resources . The Commission also recognizes and provides for what it considers appropriate exceptions to the otherwise required consultation process. As otherwise noted above, the purpose of the consultation process is to ensure that adverse impacts to wildlife resources are minimized within the identified sensitive wildlife habitats or restricted surface occupancy areas, in an order increasing well density, in a basin-wide order involving wildlife resources, or where the operator seeks a variance to a provision of the 1200-Series rules. Rule 1202 thus provides that consultation under Rule 306.c will not be required where minimization of such adverse impacts has already been considered as part of a prior COGCC action, such as previous approval of a Form 2A, Comprehensive Drilling Plan or variance, or where the CDOW has already approved a wildlife mitigation, protection, or conservation plan for the area in question. Consultation under Rule 306.c will also not be required where the proposed new well would involve a one-time increase of surface disturbance of one (1) acre or less per well site at or immediately adjacent to an existing well site; the Commission determined that such activity is expected to generate only de minimis impacts. Consultation will also not be required where the CDOW has waived consultation or where the consultation would otherwise be unwarranted, such as when an operator demonstrates that the wildlife species or habitat otherwise intended to be protected is not present. Finally, consultation will not be required where an operator seeks and obtains a Commission order that will significantly limit the extent of development within a section and where ground-disturbing activities will be limited during a biologically appropriate period of up to ninety (90) consecutive days as determined by the Director. While the period during which ground- disturbing activities are limited for wildlife habitat protection may be up to ninety (90) consecutive days for some species, it may be as few as thirty (30) days for other species. This exemption from consultation, however, will not apply to operations in occupied greater or Gunnison sage grouse sensitive wildlife habitat in certain counties identified in the rule, as these species in these areas are particularly sensitive to disturbance and vulnerable to adverse impacts from ground disturbing activity. The Commission was careful in adopting these exceptions because operators who are not covered by them are only required to consult with the CDOW and COGCC and are not automatically subjected to timing restrictions or other limitations on their operations. Central to the consultation process will be the COGCC Director’s determination of appropriate permit conditions. Such conditions are to be generally guided by a list of best management practices, which will be collaboratively developed by stakeholders and the CDOW as discussed below . To ensure the proper evaluation and selection of conditions of approval, the Commission has also established specific factors which it believes the Director should consider, among other case-by-case considerations, in establishing appropriate permit conditions. These factors are intended to ensure that the adverse impacts and means to minimize those adverse impacts are appropriately evaluated by the COGCC Director in determining any conditions of approval deemed necessary to minimize adverse impacts to wildlife resources. As required by HB 07-1298, Rule 1202 provides that no permit-specific condition of approval for wildlife habitat protection shall be imposed without surface owner consent. This prohibition includes permit-specific conditions for wildlife habitat protection that modify, add to, or differ materially from the general operating requirements in Rules 1203 and 1204. The Commission anticipates that if the surface owner does not consent to a permit-specific condition recommended by the CDOW, then the COGCC Director will consider whether minimizing adverse impacts from the proposed activity can be acceptably achieved through alternative conditions to which the surface owner will consent. The Commission also expects that if such alternative conditions cannot be identified, then the Director will weigh the impact to wildlife resources if the condition in question is omitted versus the impact to the operator and the State if the permit or approval is withheld. In some circumstances, the Director may issue the permit or approval without the condition. In other circumstances, the Director may withhold the permit or approval because unacceptable impacts to wildlife resources would otherwise result. In no event, however, would the permit or approval be issued with permit-specific wildlife conditions to which the surface owner has not consented. This decision would be made on a case-by-case basis and will be subject to review by the Commission. The Commission believes that this approach is consistent with the statutory mandate to balance recovery of the oil and gas resource with protection of Colorado’s wildlife resources.

The Commission intends that the list of best management practices will be developed in the following manner. By January 1, 2009, COGCC staff will form a stakeholder group to develop a compilation of science-based, technologically, and economically feasible practices for minimizing adverse impacts from oil and gas operations in sensitive wildlife habitat. This group will include COGCC and CDOW staff as well as representatives of the oil and gas industry, wildlife and outdoor groups, and surface and mineral owners. Subgroups may be formed to address different types of sensitive wildlife habitat or different oil and gas development basins as appropriate. The participants will seek to develop consensus recommendations for presentation to the Commission by June 2009. The Commission will consider the resulting recommendations at one of its regularly scheduled meetings, and it will take such action on them as it deems appropriate. After approval by the Commission, the list of best management practices will be published in a guidebook, maintained on the Commission’s website, and updated periodically as appropriate.

3. Rule 1203. – GENERAL OPERATING REQUIREMENTS IN SENSITIVE WILDLIFE HABITATS AND RESTRICTED SURFACE OCCUPANCY AREAS Basis : The statutory basis for this Rule is section 34-60-128(3)(d), C.R.S. Purpose : As noted above, the Commission recognizes that each producing basin may have or otherwise require the implementation of different best management practices to minimize adverse impacts from oil and gas development activities to wildlife resources. The Commission also recognizes that application of these best management practices is often best completed as part of a case-by-case analysis. However, the Commission believes there are also general operating conditions that can reasonably be applied across the state in sensitive wildlife habitats and, where development is allowed, in restricted surface occupancy areas. These conditions will help to minimize adverse impacts to wildlife resources in those sensitive wildlife habitats and restricted surface occupancy areas.

Rule 1203 sets out sixteen (16) general operating requirements with which operators must comply when conducting oil and gas operations within sensitive wildlife habitat and restricted surface occupancy areas . They include educating employees about wildlife conservation practices, minimizing rig mobilization and demobilization, consolidating new facilities, roads, and rights-of-way, using boring instead of trenching across perennial streams considered critical fish habitat, and other measures. Several of the provisions of Rule 1203 had been originally proposed for applicability state wide, such as treating waste water pits to control mosquito larvae that may spread West Nile Virus or installing wildlife crossovers and escape ramps for certain trenches created during pipeline construction. The Commission determined, however, that requiring these practices only in sensitive wildlife habitat and restricted surface occupancy areas would strike the appropriate balance at this time between development of the oil and gas resource and minimization of adverse impacts to wildlife resources. The Commission believes that these general operating requirements are cost effective and technically feasible means of avoiding, minimizing or mitigating some of the adverse impacts of oil and gas development to wildlife resources. The Commission also believes that these general operating requirements can be practically and economically incorporated into standard industry practices, and the Commission heard evidence that in certain cases operators already have undertaken or have incorporated the activities in question into their operations. The Commission recognizes that there are some costs associated with the implementation of these requirements . However, the Commission believes that most of the practices required by the general operating requirements for sensitive wildlife habitats and restricted surface occupancy areas in Rule 1203 are simply good operating practices that can be addressed through more effective planning of oil and gas operations. The Commission believes that in many instances, the actual cost of implementing these requirements is de minimis, such as requiring “wildlife appropriate” seed mixes or fencing when undertaking seeding or fencing already required under the COGCC regulations. The Commission also believes that the costs of such requirements can be effectively minimized by the operator through better planning. Further, the Commission believes the costs of compliance, where present , are outweighed by the benefits provided to wildlife. Lastly, the Commission notes that the industry parties themselves proposed the regulatory adoption of most of these general operating requirements for sensitive wildlife habitats.

For several of the operating practices required for activities within sensitive wildlife habitat and restricted surface occupancy areas , the Commission provided that they must be utilized only where allowed by the surface owner. This includes using wildlife-appropriate fencing, mowing or brushhogging vegetation, or using topographic features and vegetative screening to create seclusion areas. The Commission believes that these provisions provide appropriate protection for the interests of surface owners while also minimizing adverse impacts to wildlife resources. The Commission also recognizes that, despite their generally applicable nature, in some specific situations there may be need for relief from these general operating requirements . The need for case by case variance is something the COGCC has historically acknowledged and these generally applicable operating requirements would be subject to modification through the consultation process under Rule 306.c.

4. Rule 1204. – OTHER GENERAL OPERATING REQUIREMENTS Basis : The statutory basis for this Rule is section 34-60-128(3)(d), C.R.S. Purpose : Rule 1204 provides for 5 general operating requirements that will be required for oil and gas operations statewide to minimize adverse impacts to wildlife resources . They include installation and utilization of bear-proof dumpsters and trash receptacles for food-related trash in certain areas of the state, disinfecting certain equipment to kill whirling disease spores when conducting operations in designated Cutthroat Trout habitat, planning new transportation networks and new oil and gas facilities to minimize surface disturbance and the number and length of oil and gas roads, establishing staging and chemical storage areas outside of riparian areas and floodplains, and using minimum practical construction widths for new rights-of-way where pipelines cross riparian areas, streams and critical habitats. Again, the Commission recognizes that there is some cost associated with the implementation of these requirements. The Commission believes that most of the general operating requirements are simply good operating practices, can be addressed through more effective planning of oil and gas operations and that the costs of such requirements can be minimized by the operator through more effective planning. As above, the Commission heard evidence that in certain cases operators already have undertaken or have incorporated the activities in question into their operations. The Commission also believes the minimal costs of compliance are outweighed by the benefits provided to wildlife and are clearly the types of reasonable requirements that the General Assembly would expect to be part of the COGCC’s implementation of HB 07-1298. Lastly, the Commission once again notes that the industry parties themselves supported the regulatory adoption of most of these general operating requirements, although the industry parties sought to limit the application of the requirements to sensitive wildlife habitat. The Commission also recognizes in Rule 1204 that, despite their generally applicable nature, in some specific situations there may be need for relief from these general operating requirements . The need for case by case variance is something the COGCC has historically acknowledged and these generally applicable operating requirements would be subject to modification through consultation under Rule 306.c.

5. Rule 1205. – REQUIREMENTS IN RESTRICTED SURFACE OCCUPANCY AREAS Basis : The statutory basis for this Rule is section 34-60-128(3)(d), C.R.S. Purpose : The Commission believes there are some areas and species that require more protection in order for the COGCC to satisfy its statutory charge to minimize the adverse impacts of oil and gas development to wildlife resources. These are areas that are critical to the conservation of the species or habitats in question and, as such, are entitled to a higher level of protection , and oil and gas development within those areas is to be avoided to the maximum extent technically and economically feasible when planning and conducting new oil and gas development operations. The Commission anticipates that if an operator seeks to construct an oil and gas location in a restricted surface occupancy area notwithstanding the admonition in Rule 1205 to avoid such an area, the operator will either make an affirmative showing to the Director that avoidance of the area is either technically or economically infeasible, or that they fit within one of the exceptions set out in Rule 1205.a and described below. The Commission does not anticipate that such an operator would need to enter into a consultation with the CDOW as to whether it is technically or economically feasible to avoid a restricted surface occupancy area , although consultation may be required to determine conditions of approval for such location . The Commission, however, recognizes that there are instances where deviations from the requirements of restricted surface occupancy areas are and should be appropriately allowed. One exception allows for deviation from the requirements of restricted surface occupancy areas to address a risk to public health safety, welfare or the environment and is intended to allow the Director to balance the risk to the wildlife resource from allowing deviation from the requirements of the restricted surface occupancy area with the risk to public health, safety, welfare or the environment posed through enforcement of the requirements. It is the intent of the COGCC to conserve wildlife resources where possible, but where such conservation itself poses a risk to public health, safety, welfare or the environment or would otherwise prevent the Director from appropriately addressing that risk, the Director must be able to take whatever action is necessary to address the risk, while continuing to conserve wildlife resources where possible. The other exceptions are similar to and have been adopted for the same reasons as the analogous exceptions to consultation under Rule 1202. These include exceptions from the general requirement to avoid restricted surface occupancy areas where activities in such an area have been authorized following consultation under Rule 306.c or as part of a Comprehensive Drilling Plan, upon a demonstration that the identified habitat is not present, or when specifically exempted by the CDOW.

The Commission also wanted to ensure that the creation of restricted surface occupancy areas would not unduly impair existing and routine oil and gas operations and has adopted a regulatory provision to accomplish that. Existing wells that are located within areas now defined as restricted surface occupancy areas can continue production and operation, and routine maintenance, repairs, and replacements may take place. Also, emergency operations in restricted surface occupancy areas may be undertaken as necessary to prevent a risk to public health, safety, welfare or the environment. Further, activities at such location which are intended to benefit wildlife, such as reclamation or habitat improvement, can also be undertaken. However, any 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, unless one of the exceptions noted above applies. The Commission considered the effect the provisions of Rule 1205 would have on non-emergency workovers of wells , including uphole recompletions, within restricted surface occupancy areas and anticipates that such activities would be allowed upon Director approval. The Commission intends that such workovers would be scheduled to occur during a period and in a manner that minimizes impacts to the species for which the restricted surface occupancy area was created, developed in coordination with the CDOW.

Lastly, to accommodate ongoing or pending permit activity, Rule 1205. will not apply to a Form 2 or 2A approved by the Director prior to May 1, 2009 on federal land or April 1, 2009 on all other land. In order to accommodate and incentivize early consultations on oil and gas locations in restricted surface occupancy areas, Rule 1205. also does not apply until January 1, 2010, for any oil and gas location where the operator has in good faith initiated and is diligently pursuing consultation begun prior to May 1, 2009 on federal land or April 1, 2009 on all other land, pursuant to Rule 306.c. or Rule 216 .

The Commission notes that restricted surface occupancy areas include areas within 300 feet of Cutthroat Trout habitat as well as areas within 300 feet of Gold Medal streams and lakes. A number of parties testified that additional riparian areas should be designated as restricted surface occupancy areas because of their importance to fish and wildlife. The Commission decided not to designate additional riparian areas as restricted surface occupancy areas at this time. Instead, the Commission directed the COGCC staff to convene a stakeholder process during the first half of 2009 to discuss and attempt to develop consensus on this issue. Based upon the outcome of that stakeholder process, the Commission may initiate a subsequent rulemaking proceeding during 2009 to further address the issue. APPENDIX PART III FEE STRUCTURE As of July 1, 1999 DRILLING PERMIT Form 2 $0/well RECOMPLETION Form 2 $0/well PERMIT PIT PERMIT Form 15 $0/pit CHANGE OF Form 10 $0/well OPERATOR DISPOSAL/INJECTION Form 2 $0/well PERMIT OFFSITE LAND Form 28 $0/site TREATMENT HEARING . $0 APPLICATION HEARING . $0 PROTEST/INTERVENTI ON GENERAL MAILING . $0/year SUBSCRIPTION APPENDIX VI STATE WIDE PROTECTION ZONES FOR SURFACE WATER SUPPLY AREAS APPENDIX VII RESTRICTED SURFACE OCCUPANCY APPENDIX VIII SENSITIVE WILDLIFE HABITAT _____________________________________________________ Editor’s Notes History Section 310 eff. 9/30/2007.

Delete Section 310B eff. 9/30/2007.

Sections 328, 329 eff. 05/30/2008.

Entire Rule eff. 04/01/2009.