100 SERIES
DEFINITIONS
COMMERCIAL DISPOSAL WELL means an injection well that receives Class II exploration and production waste from multiple non-owner operators.  
FLUID means any material or substance which flows or moves whether in a semisolid, liquid, or gas form or state.
UIC AQUIFER means a geological formation, group of formations, or part of a formation that is capable of yielding a significant amount of water to a well or spring. 
UNDERGROUND SOURCE OF DRINKING WATER means an UIC Aquifer or its portion:
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) Currently supplies drinking water for human consumption; or
(2) Contains fewer than 10,000 mg/l total dissolved solids
800 SERIES
UNDERGROUND INJECTION FOR DISPOSAL AND ENHANCED RECOVERY PROJECTS

801.	CLASS II UNDERGROUND INJECTION CONTROL WELLS.
a.	An injection well will not be authorized if the proposed well or operations will result in the presence of any physical, chemical, biological or radiological substance or matter in an Underground Source of Drinking Water that may adversely affect the health of persons or cause a violation of any of the U.S. Environmental Protection Agency’s National Primary Drinking Water Regulations, 40 C.F.R. Part 141. Only the version of 40 C.F.R. Part 141 in effect as of November 2, 2020 applies to this rule; later amendments do not apply.  40 C.F.R. Part 141 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, and at the U.S. Environmental Protection Agency, Region 8, 1595 Wynkoop St, Denver, CO 80202, and is available online at https://www.epa.gov/sites/production/files/2015-11/documents/howepargulates_cfr-2003-title40-vol20-part141_0.pdf. 

b.	An injection well will not be authorized if the proposed well or operations will result in the presence of any physical, chemical, biological or radiological substance or matter that will cause a violation of any applicable domestic or agricultural use standards as adopted in 5 C.C.R. §§ 1002-41 & 1002-41.5 (“WQCC Regulation 41”) or 5 C.C.R. § 1002-42 (“WQCC Regulation 42”).  Only the versions of WQCC Regulation 41 and WQCC Regulation 42 that are in effect as of November 2, 2020 applies to this rule; later amendments do not apply.  WQCC Regulation 41 and WQCC Regulation 42 are 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, and at the Colorado Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, CO 80246, and are available online at https://www.colorado.gov/pacific/cdphe/water-quality-control-commission-regulations.
c.	Class II injection wells will not be permitted in areas where they would inject into a formation which is separated from any Underground Source of Drinking Water by a confining formation with known open faults or fractures that would allow flow between the injection zone and Underground Source of Drinking Water within the Area of Review.
d.	Injection zones will not be permitted within 300 feet in a vertical dimension from the top of any Precambrian basement formation.
802.	UIC AQUIFER EXEMPTIONS. 
a.	Criteria for UIC Aquifer exemption. An UIC Aquifer or a portion thereof may be designated by the Director or the Commission as an exempted UIC Aquifer, in connection with the filing of an application pursuant to Rules 803, 808, 809 or 810, and after coordination with  the Colorado Department of Public Health and Environment, Water Quality Control Division and U.S. Environmental Protection Agency, if it meets all of the following criteria: 
(1)	It does not currently serve as an Underground Source of Drinking Water and it is not classified for domestic use by the Water Quality Control Commission;
(2)	The applicant demonstrates that it cannot now and will not in the future serve as a source of drinking water for one of the following reasons: 
A.	It is mineral, hydrocarbon, or geothermal energy producing, or can be demonstrated by a person filing an application pursuant to Rules 803, 808, 809, or 810 to contain minerals or hydrocarbons that, considering their quantity and location, are technologically feasible to develop and can be commercially produced; or
B.	It is so contaminated that it would be economically or technologically impractical to render the water fit for human consumption.
(3)	The applicant demonstrates that it cannot now and will not in the future serve as a source of agricultural water for one of the following reasons:
A.	It is mineral, hydrocarbon, or geothermal energy producing, or can be demonstrated by a person filing an application pursuant to Rules 803, 808, 809, or 810 to contain minerals or hydrocarbons that, considering their quantity and location, are technologically feasible to develop and can be commercially produced; or
B.	It is so contaminated that it would be economically or technologically impractical to render the water fit for agricultural use.
b.	UIC Aquifer Exemption Public Notice.  If an UIC Aquifer exemption is required as part of an injection permit application process, the injection well applicant will apply for an UIC Aquifer exemption. This application will contain data and information that show the applicable UIC Aquifer exemption criteria set forth in Rule 802.a are met. After evaluation of the application and prior to designating an UIC Aquifer or a portion thereof as an exempted UIC Aquifer, the Director will publish a notice of proposed designation on the Commission’s website and in a newspaper of general circulation serving the area where the UIC Aquifer is located. The notice will identify such UIC Aquifer or portion thereof which the Director proposes to designate as exempted, and will state that any interested person may request the Commission to hold a hearing. 
c.	Evaluation of Written Requests for Public Hearing.  Written requests for a public hearing before the Commission will be reviewed and evaluated by the Commission to determine if the criteria set forth in Rule 802.a have been met. If, within 30 days after publication of the notice, the Commission receives a hearing request for which the Director determines the criteria set forth in Rule 802.b are met, the Commission will hold such a hearing pursuant to Rule 510. If no request for hearing is filed within 30 days, the UIC Aquifer or portion thereof will be considered exempted 30 days after publication of the notice.
803.	APPLICATION REQUIREMENTS FOR CLASS II UNDERGROUND INJECTION CONTROL WELLS.
a.	Unless otherwise noted in this section, the requirements of this section apply to all new Class II underground injection control wells, including: Dedicated Injection Wells (disposal and enhanced recovery); Simultaneous Injection Wells, and Commercial Disposal Well Facilities.
b.	An application for a Class II underground injection control well will satisfy the 300 Series permitting requirements, including submission of a Form 2A, Oil and Gas Location Assessment, and Form 2, Application for Permit to Drill, as applicable.
c.	Multiple Disposal Well Applications.  The injection zone radius for disposal wells will not interfere with the injection zone radius of any other disposal wells. This Rule 803.c will not apply to enhanced recovery floods.
d.	Neither construction of nor operation of a Class II underground injection well will occur without the Director’s approval of a Form 31, Underground Injection Formation Permit Application and Form 33, Injection Well Permit Application. 
(1)	Form 31, Underground Injection Formation Permit Application.  Form 31 permits the injection zone, and will be approved prior to completing an injection zone. A Form 31, Underground Injection Formation Permit Application – Intent, must be approved prior to sampling, stimulating, and testing the Well(s).  A Form 31, Underground Injection Formation Permit Application – Subsequent must be approved prior to injection.
(2)	Form 33, Injection Well Permit Application.  Form 33 permits the injection well, and will be approved prior to completing the well. A Form 33, Injection Well Permit Application – Intent, must be approved prior to sampling, stimulating, and testing the Well(s).  A Form 31, Underground Injection Formation Permit Application – Subsequent must be approved prior to injection.
e.	Withholding Approval of Underground Disposal of Class II Exploration and Production Waste.  If the Director determines that a proposed Class II underground injection well is not protective of public health, safety, welfare, applicable Colorado water quality standards, the environment and wildlife resources, and will not protect against adverse environmental impacts on any air, water, soil, or biological resource resulting from oil and gas operations, the Director will deny the Form 31, Underground Injection Formation Permit Application and any related Form 33, Injection Well Permit Application in writing. Pursuant to Rule 503, the Operator may seek the Commission’s review of the Director’s rejection of a Form 31 and Form 33 application. 
f.	Maximum Allowable Injection Rate, Total Volume and Pressure. 
(1)	The Director will set the maximum allowable injection rate, total volume, and surface injection pressure with the approved Form 31 - Subsequent and Form 33 - Subsequent.  
A.	Operators will perform seismic monitoring if the permitted injection rate exceeds 10,000 barrels per day.
B.	Injection wells will initially be permitted for an injection volume based on a 1/4 mile radius from the completed interval in the injection zone. The 1/4 mile radius will be measured from the surface location(s) for proposed vertical disposal well(s), or the completed portion of the wellbore(s) in the injection zone in drifted, directional, or horizontal wells.
C.	Operators may request a volume increase by submitting a Form 4, Sundry Notice such that the radius will increase to an injection volume based on a 1/2 mile radius from the completed interval in the injection zone.
D.	Except during hydraulic fracturing, the maximum allowable injection pressure will be set below the fracture gradient of the injection formation, as determined by a step-rate injection test in the injection well, a step rate injection test in an offset well completed in the same injection zone, or other test acceptable to the Director. The maximum allowable injection pressure will assure that the pressure in the injection zone during injection does not initiate new fractures or propagate existing fractures. Until a step-rate injection test is performed, the maximum allowable injection pressure will be set consistent with a formation pressure gradient of 0.6 pounds per square inch (psi) per total vertical foot from surface to the uppermost injection perforation.
g.	Form 31, Underground Injection Formation Permit Application – Intent.  An application for an injection well will include the following information:
(1)	Operator.  The Operator of the well or the designated Operator of a unitized or cooperative project will execute the application.
(2)	Map and List of Addresses.  The parties listed in Rule 803.g.(2).A–B will be specifically outlined and identified on a base map, and a related list of addresses will be provided with the application.
A.	All Surface Owners:
i.	Within 1/2 mile of the surface location(s) for proposed vertical disposal well(s);
ii.	Within 1/2 mile of the completed portion of the wellbore(s) in the injection zone in directional, or horizontal wells; or
iii.	If a field-wide system is proposed, all Surface Owners of record in the field and within 1/2 mile of the unit or project boundary. 
B.	All mineral Owners:
i.	Of all oil and gas wells currently producing from the proposed injection zone within 1/2 mile of the surface location(s) for proposed vertical disposal well(s);
ii.	Within 1/2 mile of the completed portion of the wellbore(s) in the injection zone in drifted, directional, or horizontal wells; or
iii.	If a field-wide system is proposed, all mineral Owners of record in the field and within 1/2 mile of the unit or project boundary.
(3)	UIC Surface Agreements.  An UIC Surface Agreement, which may be a Surface Use Agreement, a copy of the Lease, or a Unit Operating Agreement, is required for construction or recompletion of the well at the surface location. Multiple UIC Surface Agreements are required for constructing or recompleting the well if the injection zone is beneath or crosses onto the property of different Surface Owner(s). All UIC Surface Agreements with Surface Owners above the completed interval in the injection zone will specifically allow for use of pore space within the injection zone below the ground surface.  
A.	UIC Surface Agreement(s) for pore space use in the injection zone will include a 1/4 mile buffer around the surface hole location and a 1/4 mile buffer around the completed interval in the well, projected to surface in plan view for vertical, directional, and horizontal wells, in both new wells and recompleted wells.
B.	For a volume increase request pursuant to Rule 803.f.(1).C, UIC Surface Agreement(s) will address pore space within a 1/2 mile buffer around the completed interval in the well, projected to surface in plan view for vertical, directional, and horizontal wells, in both new wells and recompleted wells.
C.	UIC Surface Agreement(s) will state explicitly that the injected fluids may contain Exploration and Production Waste from Oil and Gas Operations.
(4)	Surface Facility Diagram and Process Flow Diagram.  A diagram of the surface facility showing all Pipelines and Tanks associated with the system and a process flow diagram.
(5)	Proposed Injection Program.  The application will include the following:
A.	An overall summary of the proposed injection program.  
B.	Geologic Formation Summary.  A geologic formation summary for all wells being converted to injection and all new injection wells. For a new injection well, the application may reference any available geophysical logging data from offset well(s) within 1 mile of the proposed injection well to estimate formation depths and thickness. Starting from the surface, down to the proposed total depth of the well, the application will include a stratigraphic chart with the geologic formations present, along with the names, descriptions, depths, and thickness from the surface to the top of Precambrian basement of the following:
i.	The formations which will receive any fluids to be injected;
ii.	The overlying and underlying confining formations capable of limiting the movement of any fluids to be injected;
iii.	The formations from which oil and gas wells are producing or have produced; and
iv.	All underground sources of drinking water.
C.	Laboratory analytical results from a representative water sample collected from the fluid to be injected, addressing all analytes listed in and following all procedures required by Rule 909.j.(1)–(4). 
D.	Injection Zone Analysis. Laboratory analytical results from a representative water sample collected from the injection zone, addressing all analytes listed in and following all procedures required by Rule 909.j.(1)–(4). If the total dissolved solids of the injection formation is determined to less than 10,000 milligrams per liter, the UIC Aquifer must be exempted pursuant to Rule 802.  Operators will evaluate disposal zones for hydrocarbon potential pursuant to Rule 408.q. For a new injection well, the applicant may provide any available representative water analysis from offset well(s) completed in the same injection formation within 1 mile of the proposed injection well for submission with a Form 31, Underground Injection Formation Permit Application – Intent. The Operator will submit a water analysis from the injection formation, collected from the disposal well(s) in the application with the Form 31, Underground Injection Formation Permit Application – Subsequent after the well(s) are completed.
E.	A description of the compatibility of the injection fluid with the injection zone.
F.	A description of the source(s) of the fluid and a description of the transport method from the source(s) to the injection well(s).
G.	A general description of the surface facilities, separation, and treatment processes.
H.	The estimated volume to be injected daily.
I.	The anticipated injection pressures and known or calculated fracture gradient. 
(6)	Seismicity Evaluation.  The application will include a seismicity evaluation with the following information: 
A.	A geological and geophysical evaluation of known transmissive or sealing faults or shear zones within 12 miles of the injection well and the potential for induced seismicity;
B.	An exhibit of the historical seismic activity within 12 miles of the proposed injection well;
C.	An exhibit showing the potential for seismic activity within 12 miles of the proposed injection well; and
D.	A wellbore diagram of the injection zone depicting the well’s bottomhole location relative to the Precambrian basement.
(7)	Oil and Gas Well Map and List.  The application will include a base map covering the area within 1 mile, as measured from the surface location(s) for proposed vertical disposal well(s), or within 1 mile of the completed portion of the wellbore(s), projected to surface in plan view in the injection zone in drifted, directional, or horizontal wells. The base map will show the proposed injection wellbore(s) and the wellbore path(s) and all oil and gas wells within a 1 mile radius of the injection wellbore(s). Labels on the map will identify all oil and gas wells within 1 mile of the proposed injection wellbore(s) that are producing from the proposed injection zone at the time of the application. A list will provide additional details for all oil and gas Wells shown on the Oil and Gas Well Map and their total depth, completed interval depths, completed formation names, and producing or injecting status at the time of application.
(8)	Domestic and Irrigation Water Wells Map and List.  The application will include a map and list of all domestic and irrigation wells of public record, within 1 mile of the proposed injection well(s), including their location and depth. 
(9)	Area of Review.  The application will include a review of all offset oil and gas Wells within 1/2 mile of proposed injection wellbore(s), describing existing isolation of injection formations, oil and gas production formations, confining formations, and underground sources of drinking water.
(10)	Remedial Corrective Action Plan.  The applicant will include a remedial corrective action plan for any offset well(s) within 1/4 mile of the proposed injection wellbore(s) in which the injection zone is not adequately plugged or otherwise isolated with cement to prevent flow into the offset well(s). The remedial corrective action plan will describe the applicant’s plan for performance of any such remedial work to plug, re-plug, or provide remedial cement for the offset wells, which the applicant may or may not operate.
A.	For a volume increase request pursuant to Rule 803.f.(1).C, the applicant will provide a remedial corrective action plan for offset wells within 1/2 mile of the proposed injection wellbore(s).
B.	This Rule 803.g.(10) does not apply to Enhanced Oil Recovery Projects where the offset well is a producing well that is part of the Enhanced Oil Recovery Project.
(11)	Stimulation Program.  The application will include a summary of any proposed stimulation program.
(12)	Disposal Formation Hydrocarbon Evaluation.  For disposal wells, the application will include the Operator’s proposed method of evaluating hydrocarbon production potential of the proposed injection zone. This Rule 803.g.(12) will not apply to enhanced recovery wells.
(13)	Class II Waste Source List.  The application will include a listing of all potential sources of Class II Exploration and Production Waste to be injected on Form 26, Source of Produced Water for Disposal and Form 14A, Source of Non-Produced Class II Exploration and Production Waste, as applicable.
(14)	Notice of Application.  A notice of application for an injection well will be given by the applicant by registered or certified mail or by personal delivery to the persons listed below.  The application will include a certificate of service demonstrating that the applicant served a copy of the application on all persons entitled to notice pursuant to the Commission’s Rules. The certificate of service will include the names and addresses of those persons the applicant notified, and the applicant will certify that notice was given by registered or certified mail, or by personal delivery. The applicant will provide notice to:

A.	Surface Owners and mineral Owners with recorded ownership interests within 1/2 mile of the proposed well(s), the Relevant Local Government in which the injection well is located and any Proximate Local Government within 1/2 mile of the surface location(s) for proposed vertical disposal well(s), or within 1/2 mile of the completed portion of the wellbore(s), projected to surface in plan view in the injection zone in drifted, directional, or horizontal wells.
B.	For a volume increase request pursuant Rule 803.f.(1).C, all persons and entities listed in Rule 803.g.(14).A within a 3/4 mile radius of the proposed injection wellbore(s).
C.	Disposal Wells.  Owners and Operators of oil and gas Wells producing from the injection zone and the recorded mineral Owner of the injection zone within 1/2 mile of the surface location(s) for proposed vertical disposal well(s), or within 1/2 mile of the completed portion of the wellbore(s), projected to surface in plan view in the injection zone in drifted, directional, or horizontal wells, and to mineral Owners of cornering and contiguous units where injection will occur into the producing zones, whichever is the greater distance.
D.	Enhanced Recovery Wells.  If injection of fluids is proposed for an enhanced recovery project, an entire copy of the application will be given by the applicant by registered or certified mail or by personal delivery to each mineral Owner of record of the reservoir involved within the unit and within 1/2 mile of the proposed unit boundary.  
(15)	Notice of Application Requirements.  The notice of application will briefly describe the injection application and include legal location, proposed injection zone(s), depth of injection, and other relevant information.
A.	The notice will specifically state that any person who would be directly and adversely affected or aggrieved by the authorization of the underground injection into the proposed injection zone, pursuant to Rule 507.a, is entitled to file, within 15 days of notification, a written request for a public hearing before the Commission, provided such request meets the petition requirements specified in Rule 803.k. 
B.	The notice will state that additional information about the operation of the proposed disposal well may be obtained at the Commission’s office and on the Commission’s website. The notice will provide the appropriate Commission staff contact information. 
C.	A copy of the notice of application will be included with the injection application filed with the Commission.
h.	Form 31, Underground Injection Formation Permit Application – Subsequent.  Within 30 days of a successful mechanical integrity test for an injection well, the Operator will file a Form 31, Underground Injection Formation Permit Application – Subsequent, which will include the following information:
(1)	Injection Zone Water Analysis.  A water analysis from the injection formation, collected from the disposal well(s) in the application, addressing all analytes listed in and following all procedures required by Rule 909.j.(1)–(4). If the total dissolved solids of the injection formation is determined to less than 10,000 milligrams per liter, the UIC Aquifer must be exempted pursuant to Rule 802.
(2)	Geophysical Logs.  Openhole resistivity and neutron/density logs from the bottom of the surface casing to total depth of the injection well.
(3)	Step Rate or Injectivity Test Documentation.  If the Operator performs a step rate test or injectivity test, the Operator will submit the test results.  
(4)	Disposal Well Hydrocarbon Evaluation Results.  Summary of the Operator’s evaluation of productivity test results in the injection formation.  This Rule 803.h.(4) will not apply to enhanced recovery wells.
i.	Form 33, Injection Well Permit Application – Intent. The Operator will file a Form 33, Injection Well Permit Application –Intent, which includes the following information:
(1)	Wellbore Diagram. A existing and proposed schematic drawing showing all casing strings with cement volumes and tops, plug back total depth, isolation devices, remedial cement work, depth of any existing open or squeezed perforations, setting depths of any existing or proposed bridge plugs, formation tops, planned perforations in the injection zone, tubing and packer size, and setting depth. 
(2)	Casing and Cementing Plan.  The application will include a full description of the proposed casing and cement in the injection well or wells. This will include any previous and proposed remedial cement work.
(3)	Casing Integrity.  For existing wells, the Operator will check the condition of the casing with a pipe analysis log or a caliper log and include a copy of the log with the application.
j.	Form 33, Injection Well Permit Application – Subsequent.  After an injection well is completed, recompleted, or after injection zones are temporarily abandoned, the Operator will file a Form 33, which will include the following as-constructed details:
(1)	Wellbore Diagram.  The subsequent report will include a final schematic drawing showing all casing strings with cement volumes and tops, plug back total depth, isolation devices, depth of any existing open or squeezed perforations, setting depths of any bridge plugs, formation tops, perforations in the injection zone, tubing and packer size, and setting depths. 
(2)	Casing and Cementing.  The subsequent report will include a full description of the final casing and cement in the injection well, any existing remedial cement confirmed during the work, and remedial cement placed during the work. 
(3)	Cement Bond Log.  Unless already provided to the Commission, to determine if the cement has been placed to adequately isolate the injection zone, production zones, and groundwater, a cement bond or other cement evaluation log will be run and provided with this report as a means of verifying cementing records.
(4)	Mechanical Integrity Testing Requirement.  Prior to application approval, the proposed disposal well must satisfactorily pass a mechanical integrity test pursuant to Rule 417 and be witnessed by the Director.
k.	Evaluation of Written Requests for Public Hearing.  Written requests for public hearing before the Commission by a person, notified pursuant to Rule 803.g notice application requirements, who may be directly and adversely affected or aggrieved by the authorization of the underground injection into the proposed injection zone pursuant to Rule 507.a, will be reviewed and evaluated by the Director. Written protests will specifically provide information about:
(1)	Possible conflicts between the injection zone’s proposed injection use and present or future use as a source of drinking water or as a source of hydrocarbon production;
(2)	Operations at the well site which may affect potential and current sources of drinking water; 
(3)	How the proposed Class II underground injection well is not protective of applicable Colorado water quality standards or public health, safety, welfare, the environment, or wildlife resources; or
(4)	How the application will not protect against adverse environmental impacts on any air, water, soil, or biological resource.
l.	Injection Well Public Notice.  The Director will publish a notice of the proposed injection permit for injection wells in a newspaper of general circulation serving the area where the well(s) is (are) located and publication on the Commission’s website. The notice will briefly describe the disposal application and include legal location, proposed injection zone, depth of injection, and other relevant information. The comment period on the proposed injection application will end 30 days after the date of publication. Written protests will be evaluated pursuant to Rule 803.k.
m.	Injection Application Deadlines.  If all of the data or information necessary to approve the injection application (a Form 31, Underground Injection Formation Permit Application – Intent, or a Form 33, Injection Well Permit Application – Intent) has not been received within 6 months of the date of approval of the application Intent, the application will be withdrawn from consideration. However, for good cause shown, a 90 day extension may be granted, if requested prior to the date of expiration.
n.	Notice of Commencement.  Within 30 days after the commencement of injection operations, the Operator will notify the Commission of the injection date by a Form 5A, Completed Interval Report.
o.	Notice of Discontinuance.  Within 10 days after the discontinuance of injection operations, the Operator will submit a Form 4, Sundry Notice to notify the Commission of the date of such discontinuance and the reasons for the discontinuance.
804.	ANALYTICAL REQUIREMENTS FOR INJECTION FLUID ANALYSES
a.	Collection and analysis of water samples for Rules 803, 808, 809, or 810 injection well applications must comply with the Commission's approved Underground Injection Control Quality Assurance Project Plan, effective October 8, 1997.
b.	Water analyses must include total dissolved solids and major anions and cations using routine U.S. Environmental Protection Agency or oilfield methods.
c.	If requested by the Director, the Operator will analyze samples for other constituents that may be present in the injection fluids.
d.	All analysis of water samples will be reported with the Electronic Data Deliverable (EDD) through the Commission’s Environmental Database on a Form 43, Analytic Sample Submittal.
805.	TIMING OF INJECTION FLUID SAMPLING AND ANALYSIS
a.	Initial Analysis.  An injection fluid analysis from a representative sample collected at the injection facility is required within 1 year of commencing injection after approval of an injection application.
b.	Periodic Analysis.  An injection fluid analysis from a representative sample collected at the injection facility is required every 5 years after the initial analysis or 5 years after the most recent change of source analysis.
c.	Change of Sources.  An injection fluid analysis is required when there is a significant change in the quality of the injection fluid and as required by Rule 806. The injection fluid analysis will address all analytes listed in and follow all procedures required by Rule 909.j.(1)–(4).
806.	FORM 26, SOURCES OF PRODUCED WATER  
a.	Operators will submit a Form 26, Source of Produced Water for Disposal before commencing injection into the proposed well(s).  

b.	Operators will submit a new Form 26, Source of Produced Water for Disposal within 90 days after any change in source water by addition of new source wells or the deletion of existing source wells.
807.	NON-PRODUCED CLASS II EXPLORATION AND PRODUCTION WASTE INJECTION
a.	Form 14A, Source of Non-Produced Class II Exploration and Production Waste.  Operators will submit and obtain approval of a Form 14A, Source of Non-Produced Class II Exploration and Production Waste for disposal prior to the injection of Class II Exploration and Production waste other than produced water, pursuant to Rule 413.b., into any formation in a dedicated Class II Underground Injection Control well. Examples of non-produced water include, but are not limited to, groundwater recovered during a remediation project or chemical treatments. 
(1)	The Form 14A will include a description of the nature and source of the fluids to be injected, the types of chemicals used to treat such fluids, and the proposed date of initial fluid injection. 
(2)	Operators will submit a Form 14A, and obtain the Director’s approval, for any new disposal facility, and for any changes in the source of non-produced Class II waste for an existing facility. 
b.	Form 14, Monthly Report of Non-Produced Class II Exploration and Production Waste Injected.
(1)	Operators engaged in the injection of approved non-produced Class II waste pursuant to Rule 807.a in a dedicated Class II Underground Injection Control well will submit a Form 14, Monthly Report of Non-Produced Class II Exploration and Production Waste Injected within 45 days after the end of each month. This report will include the type and amount of waste injected.
(2)	Operators of simultaneous injection wells will, by March 1 of each year, report to the Director the calculated injected volume for the previous year, by month, on a Form 14.
808.	SIMULTANEOUS INJECTION WELL APPLICATION REQUIREMENTS
Simultaneous Injection Well applications will:
a.	Satisfy the requirements of Rules 803, 804, 805, 806, and 807.
b.	Include downhole pump specifications, and a calculation of maximum discharge pressure created under proposed wellbore configuration. Downhole pump configurations will be designed to inject below the injection zone fracture gradient.
809.	COMMERCIAL DISPOSAL WELLS AND FACILITIES
a.	Commercial Disposal Well applications will:		
(1)	Satisfy the requirements of Rules 803, 804, 805, 806, and 807.
(2)	Meet the financial assurance requirements of Rules 706, 707, and 712.
b.	Commercial Disposal Well Facilities will perform continuous seismic monitoring. The Operator will provide seismic monitoring data to the Director upon request. 
810.	ENHANCED RECOVERY INJECTION PROJECTS 
a.	No person will perform any enhanced recovery operations, cycling, or recycling operations including the extraction and separation of liquid hydrocarbons from natural gas in connection therewith, nor will 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 following a hearing pursuant to Rule 503.g.(10). Enhanced recovery projects include at least one injection well and one production well, which may be the same well for “huff and puff” style operations.
b.	Hearing applications for enhanced recovery injection projects will include the following information:
(1)	Demonstration that the proposed project satisfies the requirements of Rules 803, 804, 805, 806, and 807, unless otherwise noted in those Rules.
(2)	Be filed by the Operator, or any one or more of the parties involved in the proposed enhanced recovery injection project.
(3)	Operator Contact.  The name, phone, email and address of all Operators in the unit.
(4)	Unit and Operating Agreements. Copies of the unit or co-operative agreement and operating agreement, unless these agreements have already been provided to the Commission.
(5)	Multiple Well Applications.  An application may include the use of more than 1 injection or production well on the same location, or on more than 1 location. Wherever feasible and applicable, the application will contemplate a coordinated plan for the entire field.
(6)	Unit Plan of Operations.  This information will supplement the Proposed Injection Program summary required by Rule 803. The Plan of Operations will describe how the enhanced recovery project will be operated as a system.
(7)	Casing and Cementing for Enhanced Recovery Injection Wells.  Wells used for injection of fluids into the producing formation will be cased with safe and adequate casing or tubing so as to prevent leakage, and will be so set or cemented that damage will not be caused to groundwater, oil, or gas resources. 
(8)	Unit Area Owners Map.  If the plan of operation involves injection of fluids for enhanced recovery operations, such map will show the names of Owners of record within the unit and within 1/2 mile of the unit boundary, indicating whether they are Surface Owners, mineral interest Owners, or working interest Owners. 
(9)	Unit Area Well Plat.  A plat showing the area involved, together with the Well or Wells, including drilling Wells and dry and abandoned Wells located thereon, all properly designated. 
(10)	Unit Area Domestic and Irrigation Water Wells Map and List.  The application will include a map and list of all domestic and irrigation wells of public record, within the unit area and within 1/2 mile of the unit boundary, including their location and depth. 
(11)	Unit Area of Review.  The application will include a review of all offset Wells within the unit area and within 1/4 mile of the unit boundary, describing existing isolation of injection formations, oil and gas production formations, confining formations, and underground sources of drinking water.
c.	Notice and Date of Hearing for Enhanced Recovery Injection Projects.  Upon the filing of an enhanced recovery injection project application, the Commission will issue a notice of hearing in accordance with Commission Rule 503.a. The application will be set for public hearing at a time designated by the Commission.
d.	Notices for Enhanced Recovery Operations.
(1)	When any well in an approved enhanced recovery unit operation is converted to or from an injection status, notice will be given on a Form 4, Sundry Notice within 30 days.
(2)	Before plugging any intake well, the Owner of the well will provide notice to the Commission. The Owner will follow the same procedures for plugging an intake well as the procedure for plugging a Well pursuant to Rule 434.a.

DEFINITIONS
100 SERIES

COMMENCEMENT OF PRODUCTION OPERATIONS means that a Well is capable of producing either separable gas or salable liquid hydrocarbons.
COMPLETED WELL. A well will be considered completed when oil or gas is produced through wellhead equipment from the producing interval(s) after the production string has been installed. 
CUTTINGS TRENCH means a depression used specifically for the onsite disposal of dried cuttings generated from drilling a well. 
FLARING means the combustion of natural gas during upstream Oil and Gas Operations, excluding gas that is intentionally used for onsite processes. Combustion required by the Air Quality Control Commission for purposes of emissions control is not Flaring.
FLOWBACK means the process of allowing fluids and entrained solids to flow from a Well following Stimulation, either in preparation for a subsequent phase of treatment or in preparation for cleanup and placing the Well into production. The term flowback also means the fluids and entrained solids that emerge from a Well during the flowback process. The flowback period begins when material introduced into the Well during the treatment returns to the surface following hydraulic fracturing or refracturing. The flowback period ends when gas is produced in separable quantities.
INVESTIGATION-DERIVED WASTE means those materials generated during site investigation and remediation activities, including but not limited to personal protective equipment, soil cuttings, drilling mud, purged Groundwater, decontamination fluids, and disposable or consumable equipment and supplies.
LAND APPLICATION means the disposal method by which treated E&P Waste is spread upon and mixed into soils. 
LAND TREATMENT means the method by which E&P Waste is treated ex situ at the land surface 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, or the addition of nutrients or microbes.
OILY WASTE means those materials containing unrefined petroleum hydrocarbons in concentrations in excess of the concentration levels in Table 915-1. Oily waste may include crude oil, condensate, or other material, such as soil, frac sand, drilling fluids, cuttings, and pit sludge that contain hydrocarbons.
POLLUTION means anthropogenic contamination or other degradation of the physical, chemical, biological, or radiological integrity of air, water, soil, or biological resource that is not authorized by the Commission’s Rules or applicable regulations promulgated by another federal, state, or local government agency.
PRODUCTIVITY TEST means a test for determination of a reservoir’s ability to produce economic quantities of oil or gas.
PRODUCTION EVALUATION means an evaluation of production potential for determination of requirements for infrastructure capacity and equipment sizing.
UPSET CONDITION means a sudden, unavoidable failure, breakdown, event, or malfunction, beyond the reasonable control of the Operator, of any equipment or process that results in abnormal operations and requires correction.
VENTING means intentionally allowing natural gas to escape into the atmosphere. 

ENVIRONMENTAL IMPACT PREVENTION
900 SERIES

901.	GENERAL STANDARDS

a.	Addressing Impacts and Potential Impacts to Public Health, Safety, Welfare, the Environment, and Wildlife Resources.  Whenever the Director has reasonable cause to determine that an Operator, in the conduct of any Oil and Gas Operations, is performing or has performed any act or practice which impacts or threatens to impact public health, safety, welfare, the environment, or wildlife resources, the Director may require the Operator to take action to prevent the potential impacts to public health, safety, welfare, the environment, or wildlife resources, including but not limited to:

(1)	Suspending operations or initiating immediate mitigation measures until the cause of the threat or potential threat to public health, safety, welfare, the environment, or wildlife resources is identified and the threat or potential threat to public health, safety, welfare, the environment, or wildlife resources is corrected.  

(2)	Submitting a Form 27, Site Investigation and Remediation Workplan, for site characterization, remediation, monitoring, permitting, and the establishment of points of compliance.

(3)	If the Director requires an Operator to take action pursuant to this Rule 901.a, the Operator may appeal the Director’s decision to the Commission pursuant to Rule 503.g.(10). The matter will not be assigned to an Administrative Law Judge pursuant to Rule 503.h. The Commission will hear the appeal at its next regularly scheduled meeting. Operators will continue to comply with any requirements identified by the Director pursuant to this Rule 901.a until the Commission makes a decision on the appeal.  The Commission may uphold the Director’s decision if the Commission determines the Director had reasonable cause to determine that an Operator’s actions impacted or threatened to impact public health, safety, welfare, the environmental, or wildlife resources, and that the action required by the Director was necessary and reasonable to address those impacts or threatened impacts.

b.	Incorporation by Reference.  Pursuant to § 24-4-103(12.5), C.R.S., the Commission hereby incorporates by reference into these 900 Series Rules the following codes, standards, guidelines, and rules of other federal agencies, state agencies, and nationally recognized organizations and associations.

(1)	Where Materials May Be Found.

A.	Copies of all materials incorporated by reference are 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.

B.	Copies of all materials incorporated by reference are also available at the office or website of the agency or organization that issued the code, standard, guideline, or rule, as specified below.

C.	For any materials that are not available to the public on the internet for no cost, copies of the materials may also be examined at any state publications depository library.

(2)	Current Version.  Only the version of the code, standard, guideline, or rule in effect as of November 2, 2020, and no later amendments or editions of the code, standard, guideline, or rule are incorporated by reference, unless otherwise specified below.

(3)	Materials Incorporated.

A.	Colorado Department of Public Health and Environment, Water Quality Control Commission (WQCC), Regulation Number 41, The Basic Standards for Ground Water, 5 C.C.R. § 1002-41, et seq. (hereinafter “WQCC Regulation 41”). Only the version of WQCC Regulation 41 in effect as of November 2, 2020 applies; later amendments do not apply. WQCC Regulation 41 may be examined at the Colorado Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, CO 80246, and is available online at https://www.colorado.gov/pacific/cdphe/water-quality-control-commission-regulations.

B.	Colorado Department of Public Health and Environment, Solid and Hazardous Waste Commission (SHWC), Regulations Pertaining to Solid Waste, 6 C.C.R. § 1007-2, et seq. (hereinafter “SHWC Solid Waste Regulations”). Only the version of the SHWC Solid Waste Regulations in effect as of November 2, 2020 applies; later amendments do not apply. The SHWC Solid Waste Regulations may be examined at the Colorado Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, CO 80246, and are available online at https://www.colorado.gov/pacific/cdphe/solid-waste-regulations.

C.	Colorado Department of Public Health and Environment, Solid and Hazardous Waste Commission (SHWC), Regulations Pertaining to Hazardous Waste, 6 C.C.R. § 1007-3, et seq. (hereinafter “SHWC Hazardous Waste Regulations”). Only the version of the SHWC Hazardous Waste Regulations in effect as of November 2, 2020 applies; later amendments do not apply. The SHWC Hazardous Waste Regulations may be examined at the Colorado Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, CO 80246, and are available online at https://www.colorado.gov/pacific/cdphe/hazardous-waste-regulations.

D.	Colorado Department of Public Health and Environment, Air Quality Control Commission (AQCC), Regulation No. 7, Control of Ozone Via Ozone Precursors and Control of Hydrocarbons Via Oil and Gas Emissions (Emissions of Volatile Organic Compounds and Nitrogen Oxides), 5 C.C.R. § 1001-9, et seq. (hereinafter “AQCC Regulation No. 7”). Only the version of AQCC Regulation No. 7 in effect as of November 2, 2020 applies; later amendments do not apply. AQCC Regulation No. 7 may be examined at the Colorado Department of Public Health and Environment, 4300 Cherry Creek Drive South, Denver, CO 80246, and is available online at https://www.colorado.gov/pacific/cdphe/aqcc-regs.

E.	Colorado State Board of Examiners of Water Well Construction and Pump Installation Contractors, Rules and Regulations for Water Well Construction, Pump Installation, Cistern Installation, and Monitoring and Observation Hole/Well Construction, 2 C.C.R. § 402-2, et seq. (hereinafter State Engineer’s Water Well Construction and Permitting Rules”). Only the version of the State Engineer’s Water Well Construction Rules in effect as of November 2, 2020 applies; later amendments do not apply. The State Engineer’s Water Well Construction Rules may be examined at the Colorado Division of Water Resources, 1313 Sherman St., Suite 821, Denver, CO 80203, and are available online at http://water.state.co.us/groundwater/BOE/Pages/BOERules.aspx.

F.	U.S. Environmental Protection Agency, Test Methods for Evaluating Solid Waste: Physical/Chemical Methods (May 2019 edition) (hereinafter, “EPA SW-846”). Only the May 2019, “Update VI” edition of EP SW-846 applies to this rule; later amendments do not apply. EPA SW-846 may be examined at the U.S. Environmental Protection Agency, Region 8, 1595 Wynkoop St, Denver, CO 80202, and is available online at https://www.epa.gov/hw-sw846/sw-846-compendium.

G.	U.S. Environmental Protection Agency, 40 C.F.R. § 60.5375a, What GHG and VOC standards apply to well affected facilities? (2016) (hereinafter, “40 C.F.R. § 60.5375a”).  Only the version of 40 C.F.R. § 60.5375a that became effective on August 2, 2016 applies to this rule; later amendments do not apply.  40 C.F.R. § 60.5375a may be examined at the U.S. Environmental Protection Agency, Region 8, 1595 Wynkoop St, Denver, CO 80202, and is available online at https://www.govinfo.gov/content/pkg/FR-2016-06-03/pdf/2016-11971.pdf.

H.	U.S. Environmental Protection Agency, Regional Screening Levels for Chemical Contaminants at Super Fund Sites (hereinafter, "EPA’s RSLs").  Only the version of EPA's RSLs in effect as of November 2, 2020 applies; later amendments do not apply.  EPA’s RSLs may be examined at the U.S. Environmental Protection Agency, Region 8, 1595 Wynkoop St, Denver, CO 80202, and are available online at https://www.epa.gov/risk/regional-screening-levels-rsls. 

I.	Western Coordinating Committee on Nutrient Management, Soil, Plant, and Water Reference Methods for the Western Region (4th edition, 2013).  Only the 4th edition (2013) of the Soil, Plant, and Water Reference Methods for the Western Region applies to this rule; later amendments do not apply.  Soil, Plant, and Water Reference Methods for the Western Region may be examined at the Soil Science Society of America, 5585 Guilford Road, Madison, WI 53711, and is available online at https://www.naptprogram.org/files/napt/publications/method-papers/western-states-methods-manual-2013.pdf. 

902.	POLLUTION

a.	Operators will prevent Pollution.

b.	Operators will prevent adverse environmental impacts on any air, water, soil, or biological resource resulting from Oil and Gas Operations and will protect and minimize adverse impacts to public health, safety, welfare, the environment, and wildlife resources.

c.	Operators will prevent the unauthorized discharge or disposal of oil, condensate, gas, E&P Waste, chemical substances, trash, discarded equipment, and other oil field waste.

d.	No Operator, in the conduct of any Oil or Gas Operation, may perform any act or practice which violates numeric or narrative 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 914. The Director may require the Operator to establish one or more points of compliance for any event of Pollution, which will be complied with by all parties determined to be a responsible party for such Pollution.

e.	No Operator, in the conduct of any Oil or Gas Operation, may perform any act or practice which constitutes a violation of any applicable air quality laws, regulations, or 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.

f.	No person may 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 accordance with the regulations pertaining to solid waste disposal sites and facilities as promulgated by the Colorado Department of Public Health and Environment.
903.	VENTING OR FLARING NATURAL GAS

a.	Notice to Local Governments and Emergency Responders. 

(1)	Prior Notice.  As soon as practicable prior to, but no later than two hours before, any planned Flaring and Venting of natural gas allowed pursuant to this Rule 903, Operators will provide verbal, written, or electronic notice to the Local Governmental Designee of the Relevant and Proximate Local Governments, if applicable, and to the local emergency response authorities. 

(2)	Subsequent Notice.  In the event of Flaring or Venting due to an Upset Condition, Operators will immediately provide verbal, written, or electronic notice to the Local Governmental Designee of the Relevant and Proximate Local Governments, if applicable, and to the local emergency response authorities.

(3)	Waiver.  Local Governments and local emergency response authorities may waive their right to notice under this Rule 903.a at any time, pursuant to Rule 302.f.(1).A.

(4)	Recordkeeping.  Operators will maintain records of notice provided pursuant to this Rule 903.a, and provide the records to the Director upon request.

b.	Emissions During Drilling Operations.

(1)	Operators will capture or combust gas escaping from the Well during drilling operations using the best available technology.

(2)	If capturing or combusting gas would pose safety risks to onsite personnel, Operators may request the Director’s approval to Vent. Operators may obtain verbal approval, but will provide a written request which includes any documentation necessary to support such approval by submitting a Form 4, Sundry Notice within 7 days. The Operator need not seek a formal variance pursuant to Rule 502.a.  A Form 23 may also be required if the criteria in Rule 428.c. are met. If Venting approved pursuant to this Rule 903.b.(2) exceeds 24 hours, the Operator must seek the Director’s renewed approval to continue venting.

(3)	Combustors will be located a minimum of 100 feet from the nearest surface hole location and enclosed.

c.	Emissions During Completion Operations.

(1)	Reduced Emission Completions Practices.

A.	Reduced Emission Completion Practices are required on all newly completed and re-completed oil and gas wells.  

B.	To comply with the Reduced Emission Completion Practices required by Rule 903.c.(1).A, unless otherwise specified in this Rule 903.c, Operators will adhere to the standards for well completion and re-completion in 40 C.F.R. § 60.5375a, as incorporated by reference in Rule 901.b.

(2)	Operators may Flare gas during completion operations with specific written approval from the Director under any of the following circumstances:

A.	The Operator obtains the Director’s approval to Flare through an approved Gas Capture Plan pursuant to Rule 903.e.

B.	The Operator submits, and the Director approves, a Form 4, Sundry Notice, allowing the Operator to flare gas that would otherwise not be permitted pursuant to Rule 903.c.

i.	On the Form 4, Sundry Notice, the Operator will explain why Flaring is necessary to protect or minimize adverse impacts to public health, safety, welfare, the environment, or wildlife resources.

ii.	On the Form 4, Sundry Notice, the Operator will estimate anticipated Flaring volume and duration.

iii.	On the Form 4, Sundry Notice, the Operator will explain its plan to connect the facility to a gathering line or otherwise utilize the gas in the future.

iv.	The Director may approve a Form 4, Sundry Notice requesting permission to Flare during completion if the Director determines that the Flaring is necessary to protect public health, safety, welfare, the environment, and wildlife resources.

C.	The Operator may direct gas to an emission control device and combust the gas if necessary to ensure safety or during an Upset Condition for a period not to exceed 24 cumulative hours. If Flaring pursuant to this Rule 903.c.(2).C exceeds 24 hours, the Operator must seek the Director’s approval to continue Flaring. Within 7 days of the Flaring event, the Operator will submit a Form 4, Sundry Notice reporting the Upset Condition or safety issues that resulted in the Flaring event and include the estimated volume of gas Flared. 

d.	 Emissions During Production.

(1)	After the Commencement of Production Operations at an Oil and Gas Location, Venting or  Flaring of natural gas produced from any Completed Well is prohibited except under the following circumstances:

A.	Gas Flared or Vented during an Upset Condition is allowed for a period necessary to address the upset, not to exceed 24 cumulative hours. Operators will maintain records of the date, cause, estimated volume of gas Flared or Vented, and duration of each Upset Condition resulting in Flaring or Venting, and will make such records available to the Director upon request. 
B.	Gas Vented during gauging, sampling, or the loading out of liquids to transport vehicles, as long as the Venting is not prohibited by AQCC Regulation No. 7, 5 C.C.R. § 1001-9, as incorporated by reference in Rule 901.b. 

C.	Gas Vented during active and required maintenance, as long as the Venting is not prohibited by AQCC Regulation No. 7, 5 C.C.R. § 1001-9, as incorporated by reference in Rule 901.b. 

D.	Gas Vented from an access point on a storage tank that does not (and that is not required by AQCC Regulation No. 7, 5 C.C.R. § 1001-9 to) employ air pollution control equipment, unless the Venting is otherwise prohibited by the Commission’s Rules or AQCC Regulation No. 7, 5 C.C.R. § 1001-9, as incorporated by reference in Rule 901.b.

E.	If approved by the Director on a Gas Capture Plan pursuant to Rule 903.e, gas Flared during a Production Evaluation or Productivity Test for a period not to exceed 60 days. 

F.	Gas Vented during a Bradenhead Test pursuant to Rule 419.

G.	Well liquids unloading, as long as the well liquids unloading employs best management practices to minimize hydrocarbon emissions as required by the AQCC Regulation No. 7, 5 C.C.R. § 1001-9, as incorporated by reference in Rule 901.b. Operators will Flare gas escaping into the air during liquids unloading if the escape of the gas poses a risk to public health, safety, or welfare due to the risk of a fire, explosion, or inhalation.

H.	Flaring approved pursuant to Rule 903.d.(3) or on a Form 4, Sundry Notice prior to November 2, 2020.

(2)	For any instance of Venting or Flaring permitted pursuant to Rules 903.d.(1).A–G for a period that exceeds 8 consecutive or 24 cumulative hours, the Operator will submit a Form 4, Sundry Notice reporting:

A.	The estimated or measured volume and content of gas Vented or Flared;

B.	Gas analysis of the gas Vented or Flared, including hydrogen sulfide; and

C.	Explanation, rationale, and cause for the Venting or Flaring event.

(3)	At wells that have Commenced Production Operations prior to November 2, 2020 that are not connected to a natural gas gathering line, the Operator may request permission from the Director to Flare natural gas, or to Vent casinghead gas, by submitting a Sundry Notice, Form 4. The Director may approve a request to Flare, or Vent casinghead gas, for a period not to exceed 12 months, if the Director determines that Flaring the gas or Venting casinghead gas is necessary to produce the Well and will protect public health, safety, welfare, the environment, and wildlife resources. The Form 4, Sundry Notice will describe:

A.	The estimated volume and content of the gas to be Flared;

B.	Gas analysis including hydrogen sulfide for the subject well;

C.	For requests based on lack of available infrastructure, the Operator will state why the Well cannot be connected to infrastructure;

D.	When the Well(s) will be connected to infrastructure, and why the Operator commenced production of the Well before infrastructure was available and whether the mineral Owner will be compensated for the Vented or Flared gas; and

E.	Options for using the gas instead of Flaring or Venting, including to generate electricity, gas processing to recover natural gas liquids, or other options for using the gas.

(4)	Measurement and Reporting.

A.	Operators will measure the volume of all gas Vented, Flared, or used at an Oil and Gas Location by direct measurement or by estimating the volume of gas Vented, Flared or used.  The volume of gas Vented, Flared, or used will be reported on a per well basis on the Operator’s Form 7, Monthly Report of Operations.

B.	Operators will notify all mineral owners of the volume of oil and gas that is Vented, Flared, or used on-lease. Operators will maintain records of such notice and provide the records to the Director upon request.

(5)	All Flared gas will be combusted in an enclosed device equipped with an auto-igniter or continuous pilot light and a design destruction efficiency of at least 98% for hydrocarbons. 

(6)	Pits. 

A.	Pits with uncontrolled actual Volatile Organic Compound (VOC) emissions of greater than 2 tons per year (tpy) will not be located within 2,000 feet of a Building Unit or a Designated Outside Activity Area.

B.	After November 2, 2020, Operators will not construct new pits with uncontrolled actual VOC emissions greater than 5 tpy. 

C.	Operators will provide the basis for their determination of applicability under Rule 903.d.(6) to the Director on a Form 4, Sundry Notice no later than November 2, 2021 for existing pits, or on a Form 15, Pit Permit for new pits.

e.	Gas Capture Plans.

(1)	Gas Capture Plan Submission.

A.	Operators will submit a Gas Capture Plan as an attachment to their Form 2A, pursuant to Rule 304.c.(12).

B.	Gas Capture Plans will demonstrate compliance with the requirements of Rules 903.b–d and include the following information:

i.	A description and map of the location of the closest or contracted natural gas gathering system or point of sale.

ii.	The name of the company operating the closest or contracted natural gas gathering system.

iii.	The Operator’s plan for connecting their facility to a natural gas gathering system, including:

aa.	Discussion of potential rights of way issues;

bb.	Construction schedules; 

cc.	Date of availability of the gas gathering line;

dd.	Whether the nearest or contracted gas gathering system has capacity to accept the anticipated gas to be produced at the location at the time of application; and

ee.	Alternatives to flaring during production operations prior to connection to gas gathering lines, including, but not limited to: onsite use, natural gas liquid processing, electrical power generation, gas to liquid, or other options.

iv.	For a Wildcat (Exploratory) Well or if the Operator anticipates conducting a Production Evaluation or Productivity Test, a description of the planned Production Evaluation or Productivity Test and any issues related to the Operator’s ability to connect to a gas gathering line. 

v.	Any anticipated safety risks that will require the Operator to allow gas to escape, rather than being captured during drilling operations, pursuant to Rule 903.b.(2).

(2)	Verification.  Operators will verify that their facility has been connected to a gathering line by submitting a Form 10, Certificate of Clearance pursuant to Rule 219.  

(3)	Compliance.  If an Operator does not connect its facility to a gathering line as described in the Operator’s Gas Capture Plan, the Director may require the Operator to shut in a Well until it is connected to a gathering line. The Operator may request a Commission hearing pursuant to Rule 503.a.(10), however, the Well will remain shut in until the Commission’s hearing occurs.

904.	EVALUATING CUMULATIVE AIR EMISSIONS IMPACTS

a.	As a condition of approving an Oil and Gas Development Plan pursuant to Rule 307.b.(1), the Commission may require an Operator to participate in studies evaluating cumulative air emissions impacts of oil and gas development, conducted in consultation with the Colorado Department of Public Health and the Environment. 

b.	The study(s) will include, but not be limited to, evaluation of:

(1)	Cumulative greenhouse gas emissions; and

(2)	Cumulative hazardous air pollutant emissions and monitoring techniques.

905.	MANAGEMENT OF E&P WASTE

a.	General Requirements.

(1)	Operator Obligations.  Operators will ensure that E&P Waste is properly stored, handled, transported, treated, recycled, or disposed to prevent threatened or actual adverse environmental impacts to air, water, soil, or biological resources or to the extent necessary to ensure compliance with the concentration levels in Table 915-1, and WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b.
  
(2)	Protecting Waters of the State.  Operators will conduct E&P Waste management activities, and construct and operate all Oil and Gas Locations, to protect the Waters of the State from adverse environmental impacts caused by E&P Waste.

(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 Form 4, Sundry Notice. Such plans will describe, at a minimum:

A.	The type(s) of waste;

B.	The proposed volume and use of the waste;

C.	The method of waste treatment;

D.	Product quality assurance;

E.	Final disposition of the waste; 

F.	A copy of any certification or authorization that may be required by other laws and regulations;

G.	A proposed timeline for reuse and recycling; and

H.	Any additional information requested by the Director.

(4)	Waste Management Plans.  Each Operator that generates E&P Waste as a result of their operations will prepare a comprehensive Waste Management Plan detailing how the Operator will treat, store, dispose, and transport all types of waste generated. The Director may require a Waste Management Plan to include a description of proposed haul routes, including any applicable Local Government traffic requirements.

A.	Operators will submit their Waste Management Plans with their Form 2A, Oil and Gas Development Plan or Oil and Gas Location Assessment, pursuant to Rule 304.c.(11).

B.	If an Operator seeks to change its E&P Waste management practice, the Operator will update its Waste Management Plan by submitting a revised Waste Management Plan for the Director’s approval or denial on a Form 4, Sundry Notice.

(5)	Should conditions at an active or closed Oil and Gas Location,  Oil and Gas Facility, or Land Application site where produced fluids and E&P Waste were generated, stored, treated, or disposed indicate contaminant concentrations in soils or Groundwater exceeding applicable standards, then further investigation, remediation, and reclamation may be required by the current Operator of record, or the last Operator of record if the location is no longer active. 

b.	E&P Waste Transportation.

(1)	Off-Site Transportation Within Colorado.  Operators will only transport E&P Waste off-site within Colorado 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.

(2)	Off-Site Transportation Outside of Colorado.  Operators will only transport E&P Waste off-site outside of Colorado for treatment to facilities authorized and permitted by the appropriate regulatory agency in the receiving state. 

(3)	Waste Generator Requirements.  Any Operator that generates E&P Waste that is transported off-site will maintain, for not less than 5 years, copies of each invoice, bill, or ticket, and such other records as necessary to document the requirements listed in Rule 905.b.(3).A–F. Such records will be signed by the transporter and provided to the Director upon request. 

A.	The date of the transport;

B.	The identity of the waste generator;

C.	The identity of the waste transporter;

D.	The location of the waste pickup site;

E.	The type and volume of waste; and

F.	The name and location of the treatment or disposal site.

c.	Produced Water.

(1)	Treatment of Produced Water.  Operators will treat produced water prior to placing it in a production pit to prevent crude oil, condensate, or hydrocarbon sheen from entering the pit.

(2)	Produced Water Disposal.  Produced water may be disposed as follows:

A.	Injection into a Class II well, permitted pursuant to the Commission’s 800 Series Rules or a Class I well permitted by EPA;

B.	Evaporation/percolation in a properly permitted pit at an Oil and Gas Location, operated in accordance with permit conditions and in a manner that prevents adverse impacts to Groundwater resources;

C.	Disposal at permitted commercial facilities; 

D.	Discharging into Waters of the State under the following conditions pursuant to the Water Quality Control Act and all applicable regulations. 

i.	Operators will provide the Colorado discharge permit number, latitude and longitude coordinates, pursuant to Rule 216.e, of the discharge outfall, and sources of produced water on a Form 26, Source of Produced Water for Disposal, and will include a U.S. Geological Survey topographic map showing the location of the discharge outfall. 

ii.	Produced water discharged pursuant to this Rule 905.c.(2).D may be put to beneficial use in accordance with applicable state statutes and regulations governing the use and administration of water. 

E.	Evaporation in a properly lined pit at a Centralized E&P Waste Management Facility permitted pursuant to Rule 907. 

(3)	Produced Water Reuse and Recycling. Operators may reuse produced water for enhanced recovery, drilling, completion, and other approved uses in a manner consistent with existing water rights and in consideration of water quality standards and 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 914.

(4)	Mitigation.  Operators may use water produced during operation of an oil or gas Well to provide an alternative domestic water supply to Surface Owners within the oil or gas field, pursuant to all applicable laws, including, but not limited to, obtaining the necessary approvals from the Water Quality Control Division for constructing a new “waterworks,” as defined by § 25-1.5-203(1)(b)(II)(A), C.R.S. Any produced water not so used will be disposed of pursuant to Rule 905.c.(2) or (3). Providing produced water for domestic use within the meaning of this Rule 905.c.(4) will not constitute an admission by the Operator that the well is dewatering or impacting any existing water well. The water produced will be to the benefit of the Surface Owner within the oil and gas field and may not be sold for profit or traded. 

(5)	Water Sharing Agreements.  Operators will submit agreements for sharing produced water for the Director’s approval or denial no less than 60 days in advance of implementing the water sharing plan. The plan will be submitted as a Waste Management Plan pursuant to Rule 905.a.(4).  

d.	Drilling Fluids.

(1)	Reuse and Recycling.  Operators may recycle drilling pit contents for reuse at another drilling pit that is properly permitted and operated pursuant to Rules 908, 909, and 910.

(2)	Treatment and Disposal.  Operators will treat or dispose of drilling fluids through:

A.	Injection into a Class II well permitted pursuant to the Commission’s 800 Series Rules;

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 pursuant to Rule 907.

(3)	Additional Authorized Disposal of Water-Based Bentonitic Drilling Fluids.  Operators may dispose of water-based bentonitic drilling fluids through one of the following methods:

A.	Drying and burial in pits on non-crop land, if:

i.	The resulting concentrations will not exceed the concentration levels in Table 915-1; and

ii.	The Director approves the Operator’s plan for closing the pit pursuant to a prior approved Form 27, Site Investigation and Remediation Workplan.
  
B.	Land Application if permitted by a Waste Management Plan approved by the Director pursuant to Rule 905.a.(4), and if the Operator complies with the following standards:

i.	Application Methods.  Acceptable methods of Land Application include, but are not limited to, production facility construction and maintenance, lease road maintenance, and offsite beneficial reuse, subject to Rule 905.a.(4).

ii.	Land Application Requirements.

aa.	The average thickness of water-based bentonitic drilling fluid waste applied will be no more than 3 inches.

bb.	Operators will incorporate the drilling fluid waste through mechanical means into the uppermost soil horizon.

cc.	The waste will be applied to prevent ponding or erosion and will be incorporated as a beneficial amendment into the native soils within 10 days of application.

dd.	Operators will not apply water-based bentonitic drilling fluids to Non-Crop Land.

ee.	Prior to application, Operators will analyze water-based bentonitic drilling fluid waste to ensure that concentrations of contaminants of concern in water-based bentonitic drilling fluids do not exceed concentrations in Table 915-1.

ff.	The results of sampling analysis demonstrating compliance with Table 915-1 will be provided to the Director upon request.

iii.	Surface Owner & Local Government Approval.  Operators will obtain written authorization from the Relevant Local Government, if required, and the Surface Owner prior to Land Application of water-based bentonitic drilling fluids and provide the written authorization to the Director upon request.

iv.	Recordkeeping.  Operators will maintain records of the information listed in Rule 905.d.(3).B.iv.aa–cc for 5 years, pursuant to Rule 206.f. Operators will provide all such records to the Director within 5 days, upon request:

aa.	The source of any water-based bentonitic drilling fluids applied;

bb.	The volume of any water-based bentonitic drilling fluids applied; and

cc.	The location where the Land Application of the water-based bentonitic drilling fluid occurred. 

v.	Operator Responsibility.  The Operator with control and authority over the Well(s) from which the water-based bentonitic drilling fluid wastes were obtained retains responsibility for the Land Application operation. All Operators will cooperate with the Director in responding to complaints regarding Land Application of water-based bentonitic drilling fluids.

e.	Oily Waste.

(1)	Treatment and Disposal.  Operators may treat or dispose of Oily Waste through one of the following methods:

A.	Disposal at a commercial solid waste disposal facility;

B.	Land Treatment onsite pursuant to 905.e.(2); or

C.	Land Treatment at a Centralized E&P Waste Management Facility permitted pursuant to Rule 907.

D.	Onsite treatment, for Oily Waste other than tank bottoms, using alternative methods described on a Form 27, Site Investigation and Remediation Workplan submitted to the Director for prior approval.

(2)	Land Treatment Requirements.

A.	Prior to commencing any Land Treatment, Operators will submit and obtain approval of a Form 27, Site Investigation and Remediation Workplan. The Form 27 will include, at a minimum:

i.	A site diagram depicting the location of the planned Land Treatment area;

ii.	The duration of the planned treatment; and

iii.	The Operator’s plan for final disposition of the treated Oily Waste.
 
B.	Operators will adhere to the approved plan provided with the Form 27, and Rules 907 and 915, when performing Land Treatment.

C.	Operators will remove free oil from the Oily Waste prior to Land Treatment.

D.	Operators will spread Oily Waste evenly to prevent pooling, ponding, and runoff.

E.	Operators will prevent contamination of stormwater runoff, Groundwater, and surface water.

F.	Operators will enhance biodegradation by routine disking, tilling, aerating, or addition of nutrients, microbes, water or other amendments, at a predetermined frequency pursuant to the approved Form 27.

G.	When Operators incorporate land-treated Oily Waste in place or beneficially reuse it, the treated waste may not exceed the cleanup concentrations in Table 915-1, including inorganic constituents and metals.

H.	Surface Owner Consent.

i.	If an Operator intends to conduct Land Treatment in an area not being utilized for Oil and Gas Operations, the Operator will obtain the Surface Owner’s consent to conduct the Land Treatment operations on the Surface Owner’s property, and provide a copy of the signed agreement with the Surface Owner to the Director with the Form 27 prior to proceeding with Land Treatment.

ii.	If an Operator intends to conduct Land Treatment on an approved Oil and Gas Location prior to completion of interim reclamation or on the surface disturbance remaining after interim reclamation, the Operator will provide notice to the Surface Owner at least 30 days before commencing the Land Treatment. Notice will, at a minimum, include a site diagram depicting the location of the planned Land Treatment area, the duration of the planned treatment, and planned final disposition of the waste.  

I.	Operators will conduct Land Treatment in a manner that does not preclude compliance with Rules 1003 and 1004.

J.	Operators will not conduct Land Treatment of Oily Waste on an Oil and Gas Location after the final Well has been plugged. Oily Waste will be treated or disposed pursuant to Rule 905.e.1.(A) or (C). 

K.	Operators will conduct Land Treatment in a manner that achieves compliance with Table 915-1 concentrations in three years or less.  If the treated waste does not comply with Table 915-1 within three years of the date of Land Treatment, the Operator will submit a Form 28, Centralized E&P Waste Management Facility Permit at least 90 days in advance of the 3 year anniversary of the Land Treatment Form 27 approval date. Failure to comply with Table 915-1 in 3 years or submit a Form 28  will result in the requirement to immediately remove and properly dispose any remaining Oily Waste pursuant to Rule 905.e.1.(A) or (C).

f.	Other E&P Waste.  Operators may treat and dispose other E&P Waste, including but not limited to workover fluids, tank bottoms, pigging wastes from pipelines, and gas gathering, processing, and storage wastes through one of the following methods: 

(1)	Disposal at a commercial solid waste disposal facility;

(2)	Treatment at a Centralized E&P Waste Management Facility permitted pursuant to Rule 907; 

(3)	Injection into a Class II injection Well permitted pursuant to the Commission’s 800 Series Rules; or

(4)	An alternative method proposed in a Waste Management Plan pursuant to Rule 905.a.(4) and approved by the Director. 
  
g.	Drill Cuttings.  Operators will treat or dispose of drill cuttings through one of the following methods:

(1)	Oily Waste.  Operators will manage the following drill cuttings as Oily Waste pursuant to Rule 905.e:

A.	Drill cuttings generated from oil-based drilling fluids;

B.	Drill cuttings that exceed Table 915-1 concentrations for organic compounds in soil; and 

C.	Drill cuttings that have not been sampled and analyzed to demonstrate compliance with Table 915-1 for organic compounds in soil.

(2)	Drill Cuttings.  Operators will demonstrate compliance with Table 915-1 through sampling and analysis. Operators may manage drill cuttings that comply with Table 915-1 and are generated using water-based bentonitic drilling fluids through one of the following methods:
 
A.	Disposal at a commercial solid waste disposal facility;

B.	Disposal at a Centralized E&P Waste Management Facility permitted pursuant to Rule 907;

C.	Subject to Surface Owner approval, Land Application as a beneficial soil amendment to native soil subject to a Waste Management Plan approved pursuant to Rule 905.a.(4).  

D.	If permitted by Rule 1003.d, and subject to Surface Owner approval, drying and burial in on-location drilling pits that are documented with a Form 27, Site Investigation and Remediation Workplan submitted for prior Director approval for closure of the pit; or

E.	Subject to Surface Owner approval, burial in a Cuttings Trench, subject to a Form 27, Site Investigation and Remediation Workplan submitted for prior Director approval.

906.	MANAGEMENT OF NON-E&P WASTE

a.	Certain wastes generated by Oil and Gas Operations that do not meet the 100 Series definition of E&P Waste are regulated as solid or hazardous wastes by the Colorado Department of Public Health and Environment, Solid and Hazardous Waste Commission (SHWC). Operators will properly identify and dispose of these wastes pursuant to applicable state and federal regulations.

b.	The SHWC Hazardous Waste Rules, as incorporated by reference in Rule 901.b, require that a hazardous waste determination be made for any non-E&P solid waste. Operators will comply with all hazardous waste storage, treatment, and disposal requirements in the SHWC’s Hazardous Waste Rules, as incorporated by reference in Rule 901.b.

c.	All non-hazardous/non-E&P wastes are considered solid waste. Operators will comply with all storage, treatment, and disposal requirements in the SHWC’s Solid Waste Rules, as incorporated by reference in Rule 901.b.

d.	Operators will not burn or bury non-E&P waste on Oil and Gas Locations. 

907.	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 907 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 E&P Waste Management Facilities may include components such as Land Treatment or Land Application sites, pits, and recycling equipment.

b.	Permit Requirements.  Before any Operator commences construction of a Centralized E&P Waste Management Facility, the Operator will file and obtain the Director’s approval of an application on a Form 28, Centralized E&P Waste Management Facility Permit and pay a filing fee established by the Commission (see Appendix III). In addition to the information required for and provided on the approved Form 2A, Oil and Gas Location Assessment, the Form 28 will contain the following:

(1)	The name, address, phone and email address of the Operator, and a designated contact person.

(2)	The name, address, phone number, email address, and written authorization of the Surface Owner of the site, if not the Operator.

(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 E&P Waste Management Facility Siting Requirements.

A.	A site plan showing drainage patterns and any diversion or containment structures, and facilities such as roads, fencing, tanks, pits, buildings, and other construction details.

B.	Scaled drawings of entire sections containing the proposed facility. The field measured distances from the nearer north or south and nearer east or west section lines will be measured at 90 degrees from said section lines to facility boundaries and referenced on the drawing. A survey will be provided including a complete description of established monuments or collateral evidence found and all aliquot corners.

C.	The facility will 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 will also be implemented to prevent access to the Centralized E&P Waste Management Facility by wildlife or domestic animals.

D.	Centralized E&P Waste Management Facilities will have a fire lane of at least 10 feet in width around the perimeter of the active treatment areas and within the facility fencing. In addition, a buffer zone of at least 10 feet will be maintained within the perimeter fire lane.

E.	Surface water diversion structures, including, but not limited to, berms and ditches, will be constructed to accommodate a 100-year, 24-hour storm event. The facility will 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 25-year, 24-hour storm event. 

F.	Operators will provide evidence that they have complied with any Local Government land use regulations and facility siting or construction or operation requirements.

G.	Operators will not construct new Centralized E&P Waste Management Facilities within 2000 feet of the nearest Building Unit or High Occupancy Building Unit, unless all Building Unit owners within 2000 feet consent to a closer location.

(6)	Waste Profile.  For each type of waste, Operators will estimate the amounts to be received and managed by the facility on a monthly average basis. For each waste type to be treated, Operators will complete a characteristic waste profile, which will include analysis of representative waste samples by an accredited laboratory.

(7)	Facility Design and Engineering.  Facility design and engineering data, incorporating Best Management Practices, including plans and elevations, design basis, calculations, and process description. Facility design, engineering, and as-constructed plans will be reviewed and stamped by a Colorado Professional Engineer (P.E.).
  
A.	Geologic data, including, but not limited to: 

i.	Type and thickness of unconsolidated soils; 

ii.	Type and thickness of consolidated bedrock, if applicable; 

iii.	Local and regional geologic structures; and

iv.	Any geologic hazards that may affect the design and operation of the facility. 
  
B.	Hydrologic data, including, but not limited to:  

i.	Water wells within 1 mile of the site boundary including, but not limited to, information such as well construction details, total depth, static water level, screened interval(s), yields, and aquifer name(s).

ii.	Surface water features within 2 miles; 

iii.	Site location in relation to the floodplain of nearby surface water features; 

iv.	Depth to Groundwater, including specifically identifying the shallowest unconfined Groundwater and any underlying Groundwater formations; 

v.	Existing quality of the shallowest Groundwater;

vi.	Hydrologic properties of the shallowest Groundwater at the location including flow direction, flow rate, and potentiometric surface; and

vii.	An evaluation of the potential for impacts to nearby surface water and Groundwater. 

C.	Engineering data, including, but not limited to:

i.	Type and quantity of material required for use as a liner, including design components; 

ii.	Location and depth of cut for liners; 

iii.	Design of leak detection system for pits or other containment systems;

iv.	Location, dimensions, and grades of all surface water diversion structures; 

v.	Location and dimensions of all surface water containment structures; and

vi.	Location of all proposed facility structures and access roads. 
 
(8)	Operating Plan.  An operating plan, incorporating Best Management Practices, including, but not limited to:

A.	A detailed description of the method of treatment, loading rates, and application of nutrients and soil amendments;

B.	Dust and moisture control;

C.	Sampling;

D.	Inspection and maintenance; 

E.	Emergency response; 

F.	Recordkeeping ;

G.	Site security;

H.	Hours of operation;

I.	Stormwater Management Plan;

J.	Noise and odor mitigation; and 

K.	Final disposition of waste. If the Operator intends to beneficially reuse treated waste, the Operator will describe the reuse and method of product quality assurance.
  
(9)	Groundwater Monitoring.

A.	Water Wells.  Operators will collect water samples from water wells known to the Operator or registered with the Colorado State Engineer, following all protocols established by Rule 615, except that the Operator will collect water samples from known water wells within 1 mile of the proposed Centralized E&P Waste Management Facility. 

B.	Site-Specific Monitoring Wells. 

i.	Upon the Director’s request, the Operator will install site-specific monitoring wells to ensure compliance with the concentration levels in Table 915-1 and WQCC Regulation 41, as incorporated by reference in Rule 901.b, by establishing points of compliance. 

ii.	All monitoring well construction must be completed pursuant to the State Engineer’s Water Well Construction and Permitting Rules, as incorporated by reference in Rule 901.b.

iii.	Where monitoring is required, the direction of flow, Groundwater gradient and quality of water will be established by the installation of a minimum of 3 monitor wells, including an up-gradient well and 2 down-gradient wells that will serve as points of compliance, or other methods authorized by the Director.

iv.	The Operator will propose for prior Director approval monitoring schedules, reporting schedules, and appropriate analyte lists.  

(10)	Surface Water Monitoring.  Where applicable, the Director will require baseline and periodic surface water monitoring to ensure compliance with Water Quality Control Commission surface water standards and classifications, including narrative standards. Operators will 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 will notify the Director of the surface water for which access was not obtained and sampling of such surface water by the Operator will not be required. 

(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 any joint operating agreement regarding maintenance, closure, and monitoring of the facility. 

c.	Permit Review.

(1)	The Director may approve the Centralized E&P Waste Management Facility permit if it protects and minimizes adverse impacts to public health, safety, welfare, the environment, and wildlife resources. The Director may require any conditions of approval that are determined to be necessary and reasonable to protect public health, safety, welfare, the environment, and wildlife resources or to protect against adverse environmental impacts on any air, water, soil, or biological resource resulting from Oil and Gas Operations, or to the extent necessary to ensure compliance with the concentration levels in Table 915-1, or WQCC Regulation 41 Groundwater standards and classifications, as incorporated by reference in Rule 901.b.

(2)	The Director may deny a Centralized E&P Waste Management Facility permit if it does not adequately protect or minimize impacts to public health, safety, welfare, the environment, and wildlife resources, or protect against adverse environmental impacts on any air, water, soil, or biological resource resulting from Oil and Gas Operations.

d.	Financial Assurance.  The Operator of a Centralized E&P Waste Management Facility will submit for the Director's approval such financial assurance as required by Rule 704 prior to the Director issuing the operating permit. 

e.	Facility Modifications.  Throughout the life of the facility, the Operator will submit proposed modifications to the facility design, operating plan, permit data, or permit conditions to the Director for prior approval through a Form 4, Sundry Notice. 

f.	Permit Expiration.  The Form 28, Centralized E&P Waste Management Facility Permit will expire 2 years after approval if the Operator has not commenced construction of the permitted facility.  

g.	Annual Permit Review.  To ensure compliance with permit conditions and the Commission’s Rules, the facility permit will be subject to an annual review by the Director. To facilitate this review, the Operator will submit an annual report summarizing operations, including the types and volumes of waste handled at the facility. The Director may require additional information. 

h.	Closure. 

(1)	Preliminary Closure Plan.  A general preliminary plan for closure will be submitted with the Form 28, Centralized E&P Waste Management Facility Permit. The preliminary closure plan will include, but not be limited to:

A.	A general plan for closure and reclamation of the entire facility, including a description of the activities required to decommission and remove all equipment, close and reclaim pits, dispose of or treat residual waste, collect samples as needed to verify compliance with soil and Groundwater standards, implement post-closure monitoring, and complete other remediation, as required. 

B.	An estimate of the cost to close and reclaim the entire facility and to conduct post-closure monitoring. Cost estimates will be subject to review by the Director to verify that the financial assurance provided pursuant to Rules 907.d and 704 is appropriate. 

(2)	Final Closure Plan.  A detailed Form 27, Site Investigation and Remediation Workplan, will be submitted at least 60 days prior to closure for approval or denial by the Director. The workplan will 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 Groundwater standards, implement post-closure monitoring, and complete other remediation, as required.
 
908.	PIT PERMITTING/REPORTING REQUIREMENTS

a.	Operators will submit a Form 15, Earthen Pit Report/Permit to the Director for review and approval prior to constructing any of the following:

(1)	All production pits;

(2)	Special purpose pits except those listed in Rules 908.c.(1) or (2);

(3)	Drilling pits; and

(4)	Multi-well pits, including those located at Centralized E&P Waste Management Facilities. 

b.	Operators will submit a Form 15, Earthen Pit Report/Permit to the Director for review and approval prior to enlarging or otherwise modifying an existing properly permitted pit.

c.	Operators will submit a Form 15, Earthen Pit Report/Permit within 30 days after constructing:

(1)	Emergency Pits, Plugging Pits, and Workover Pits if they are used in the initial phase of an emergency response; and

(2)	Cuttings Trenches approved on a Form 2A, Oil and Gas Location Assessment.

d.	In order to allow adequate time for pit permit review and approval, Operators will submit a Form 15, Earthen Pit Report/Permit at the same time they submit a Form 2A, Oil and Gas Location Assessment, or Oil and Gas Development Plan. The Director may condition approval of the Form 15, Earthen Pit Permit upon compliance with additional terms, provisions, or requirements necessary to protect public health, safety, welfare, the environment, and wildlife resources. The Director may deny a Form 15, Earthen Pit Report/Permit if the Director determines it does not provide necessary and reasonable protections for public health, safety, welfare, the environment, and wildlife resources, or that it fails to protect against adverse environmental impacts on any air, water, soil, or biological resource resulting from Oil and Gas Operations. Notwithstanding the foregoing, no Form 15 will be approved until the associated Form 2A or Oil and Gas Development Plan is approved.

909.	PITS – CONSTRUCTION AND OPERATION

a.	Operators will ensure that the pits they operate are:
	
(1)	Properly permitted through a Form 15, Earthen Pit Report approved by the Director, or registered in their names with an active Pit Facility ID;

(2)	Accurately mapped; and

(3)	Listed according to current facility records in the Commission’s database. Operators may update facility records using a Form 15, Earthen Pit Report.   

b.	Operators will construct and operate pits used for exploration and production of oil and gas in a manner that protects and minimizes adverse impacts to public health, safety, welfare, the environment, and wildlife resources, and protects against adverse environmental impacts on any air, water, soil, or biological resource resulting from Oil and Gas Operations. Operators will maintain pits and pit liners to prevent spills and releases.

c.	Operators will construct, monitor, and operate pits to provide for a minimum of 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. Operators will employ a method of monitoring and maintaining the freeboard. Operators will report any unauthorized release of fluids from a pit pursuant to Rule 912. 

d.	Operators will not store oil or any other produced liquid hydrocarbon substance in earthen pits or reservoirs, except in emergencies where such substances cannot be otherwise contained.  Operators will remove the oil or produced hydrocarbons as soon as the emergency is controlled. Operators will submit a Form 15, Earthen Pit Report for the Director’s approval within 30 days of the emergency, pursuant to Rule 908.c.

e.	No liquid hydrocarbons may be present in a pit unless the pit is specifically permitted as a skim pit. 

(1)	Immediately upon discovery or notification, Operators will remove any accumulation of oil or condensate, including free product or hydrocarbon sheen, from a pit. If the Operator is unable to immediately remove the accumulation, the accumulation will be removed within 24 hours of discovery. 

(2)	Operators will 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.  

(3)	If an Operator allows oil or condensate (free product or sheen) to accumulate in a pit, then the Director may revoke the Operator’s Form 15, Earthen Pit Permit, and require the Operator to close and remediate the pit.

f.	Operators will fence and net or install Colorado Parks and Wildlife-approved exclusion devices on all new and existing Pits pursuant to Rule 1202.a.(4). 

g.	Operators may use Multi-well Pits for a period of no more than 3 years, except as permitted pursuant to Rule 907 at a Centralized E&P Waste Management Facility. 

h.	Operators will treat produced water pursuant to Rule 905.c.(1) before placing it in a Production Pit.

i.	Operators will utilize appropriate biocide treatments to control bacterial growth and related odors. 

j.	Produced Water Quality Analyses. Beginning November 2, 2021, Operators will submit a water quality analysis for produced water for each well from which produced water is placed into a permitted or registered pit.

(1)	The water sample will be analyzed for the following:

A.	pH;

B.	Specific conductance;

C.	Total dissolved solids (TDS);

D.	Alkalinity (total, bicarbonate and carbonate as CaCO3);

E.	Major anions (bromide, chloride, fluoride, sulfate, nitrate and nitrite as N, and phosphorus);

F.	Major cations (calcium, iron, magnesium, manganese, potassium, and sodium);

G.	Other elements (barium, boron, selenium, and strontium);

H.	Naphthalene; 

I.	Total petroleum hydrocarbons (TPH) as total volatile hydrocarbons (C6 to C10) and total extractable hydrocarbons (C10 to C36); 

J.	BTEX compounds (benzene, toluene, ethylbenzene, and xylenes); and

K.	Radium (226Ra and 228Ra), lead (210Pb), bismuth (210Bi), and polonium (210Po).

(2)	Operators will submit water quality analysis data using a Form 43, and will include suitable electronic data deliverable (EDD) generated by the laboratory and a portable document format (PDF) of lab reports. Results for the samples collected pursuant to Rule 909.j.(1) will be submitted no later than May 2, 2022, or prior to pit closure, whichever is earlier.

(3)	Operators will collect samples according to standard environmental procedures.

(4)	Operators will analyze samples in an accredited laboratory using established methodologies. For those analytes with groundwater threshold concentrations listed in WQCC Regulation 41, as incorporated by reference in Rule 901.b, the analytical technique will be capable of achieving, and will achieve, reporting limits at concentrations less than the WQCC Regulation 41 thresholds in the matrix submitted. The Director may review the analytical standard used for each analyte and may request the analysis be run by a different method. 
 
(5)	As an alternative to the sampling required by Rule 909.j.(1)–(4), for produced water transported to pits at Centralized E&P Waste Management Facilities, the transporting Operator may submit a Form 4, Sundry Notice to request the Director’s approval for an alternative sampling program to consolidate the number of samples required from the same formation(s).

910.	PIT LINING REQUIREMENTS AND SPECIFICATIONS

a.	Except for Cuttings Trenches and pits constructed as an initial emergency response measure pursuant to Rule 908.c.(1), all pits constructed after November 2, 2020 will be lined. 

b.	Skim Pits.  Operators will not construct new skim pits. All existing skim pits, regardless of date of construction, will be lined. For any unlined skim pits in existence on November 2, 2020, the Operator will submit a Form 27, Site Investigation and Remediation Workplan, outlining the Operator’s plan to delineate and remediate any associated impacts and a plan to either properly line or close the pit. The Form 27 for an unlined skim pit must be submitted to the Director by November 16, 2020. If the pit will be lined and returned to service, the Operator will also obtain Director approval of a Form 15, Earthen Pit Permit/Report. 

c.	Operators will construct all pits according to the following specifications:

(1)	Materials used in lining pits will 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 will be designed, constructed, installed, and maintained in accordance with the manufacturers’ specifications and good engineering practices. Operators will maintain records demonstrating that the Operator followed manufacturers’ specifications, and provide them to the Director upon request.

(3)	Field seams will be installed and tested in accordance with manufacturer specifications and good engineering practices. Operators will maintain testing results, repair documentation (including the dates of tests and repairs), and provide them to the Director upon request. 

d.	Operators will construct all pits, except those at Centralized E&P Waste Management Facilities, according to the following specifications: 

(1)	Liners will have a minimum thickness of 24 mils. The synthetic or fabricated liner will cover the bottom and interior sides of the pit with the edges secured with at least a 12 inch deep anchor trench around the pit perimeter. The anchor trench will be designed to secure, and prevent slippage or destruction of, the liner materials. 

(2)	The foundation for the liner will be constructed with material containing no sharp rocks, debris or other material that could puncture the liner. The foundation for the liner will have a minimum thickness of 12 inches after compaction, cover the entire bottom and interior sides of the pit, and be constructed so that the hydraulic conductivity will not exceed 1.0 x 10-7 cm/sec after testing and compaction. Operators will maintain compaction and permeability test results measured in the laboratory and field and provide the results to the Director upon request. 

(3)	As an alternative to the soil foundation described in Rule 910.d.(2), Operators may construct the foundation 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 will be padded with soil or synthetic matting type material and will be free of sharp rocks or other material that are capable of puncturing the liner. Each synthetic liner will have a minimum thickness of 24 mils. 

e.	Operators will construct pits used at Centralized E&P Waste Management Facilities according to the following specifications: 

(1)	Liners will have a minimum thickness of 60 mils. The synthetic or fabricated liner will cover the bottom and interior sides of the pit with the edges secured with at least a 12 inch deep anchor trench around the pit perimeter or in accordance with the liner manufacturer’s specifications. The anchor trench will be designed to secure, and prevent slippage or destruction of, the liner materials. 

(2)	The foundation for the liner will be constructed with material containing no sharp rocks, debris or other material that could puncture the liner. The foundation for the liner will have a minimum thickness of 24 inches after compaction, cover the entire bottom and interior sides of the pit, and be constructed so that the hydraulic conductivity will not exceed 1.0 x 10-7 cm/sec after testing and compaction. Operators will maintain compaction and permeability test results measured in the laboratory and field and provide them to the Director upon request. 

(3)	As an alternative to the soil foundation described in Rule 910.e.(2), Operators may use 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. 

(4)	As an alternative to the soil foundation described in Rule 910.e.(2), Operators may use a double synthetic liner system. However, the bottom and sides of the pit will be padded with soil or synthetic matting type material and will be free of sharp rocks or other materials that are capable of puncturing the liner. Each synthetic liner will have a maximum thickness of 60 mils.

(5)	All pits will be constructed and operated with a leak detection system.

f.	The Director may require the use of additional liners or a leak detection system for the pit or other equivalent protective measures, including but not limited to, increased recordkeeping requirements, monitoring systems, and underlying gravel filled sumps and lateral systems. In making such a determination, the Director will consider the site-specific information provided by the Operator, including but not limited to surface and subsurface geology, the presence and depth to Groundwater, the quality of the produced water, the hydraulic conductivity of the surrounding soils, the distance to surface water and water wells, and the type of liner.

911.	CLOSURE OF OIL AND GAS FACILITIES
 
a.	Operators will close all Oil and Gas Facilities, including Drilling Pits and Cuttings Trenches, in accordance with an approved Form 27, Site Investigation and Remediation Workplan. 

(1)	Operators will obtain the Director’s approval of the Form 27, Site Investigation and Remediation Workplan prior to conducting any investigation or closure operations.

(2)	The Form 27, Site Investigation and Remediation Workplan will include a description of the proposed investigation and remediation activities pursuant to Rule 913. 

(3)	Operators will close and remediate emergency pits as soon as the initial phase of emergency response operations are complete or any process upset conditions are controlled.

(4)	Oil and Gas Facility closure pursuant to this Rule 911.a will be at the time of final site closure, plugging and abandonment, or decommissioning, unless the Director determines that a substantive change to the site requires a Form 27, or a reportable spill or an historic impact is discovered during facility operation or removal.  

b.	Discovery of a Spill or Release During Closure.  If an Operator discovers a spill or release during closure operations, the Operator will report the spill or release on a Form 19, Spill/Release Report, pursuant to Rule 912. 

c.	Inactive Oil and Gas Facilities.  Operators will report any equipment  at an Oil and Gas Location, including a Pit, that is not in use for a period of 12 months or more to the Director via Form 4, Sundry Notice. On its Form 4, the Operator will describe the necessity for keeping the equipment or improvement and a schedule for returning it to service. 

(1)	If the Director approves the return to service schedule, the Operator will submit a Form 4, Sundry Notice notifying the Director within 30 days of return to service.

(2)	The Director may require closure or removal of the inactive equipment or improvement, subject to an approved Form 27, Site Investigation and Remediation Workplan.    

(3)	Operators will maintain any facilities or equipment that are not in use in compliance with all applicable Commission Rules.

d.	Pit Closure.

(1)	Pit Evacuation. Operators will treat or dispose of E&P Waste pursuant to Rule 905 prior to backfilling and site reclamation. 

(2)	Operators will collect a sufficient number of representative samples from locations beneath a pit to demonstrate that no leakage of managed fluids has occurred. Operators will ensure that any soil left in place meets the cleanup concentration listed in Table 915-1.

(3)	Liner Disposal. 

A.	Synthetic Liner Disposal. Operators will remove and dispose synthetic liners pursuant to all state and federal requirements for solid waste disposal. 

B.	Constructed Soil Liners. Operators may remove constructed soil liner material for treatment or disposal. Alternatively, if an Operator leaves the constructed soil liner material in place, the Operator will rip the material and mix it with native soils in a manner to alleviate compaction and prevent an impermeable barrier to infiltration and ground water flow. Operators will demonstrate that the resulting material meets cleanup concentrations for contaminants of concern listed in Table 915-1.

912.	SPILLS AND RELEASES

a.	General. 

(1)	Immediately upon discovering any spills or releases of E&P Waste, or produced fluids or unauthorized release of natural gas, regardless of size or volume, Operators will control and contain the spill or release to protect public health, safety, welfare, the environment, and wildlife resources.

(2)	Operators will immediately investigate, clean up, and document impacts resulting from spills and releases.

(3)	The Director may require the Operator to perform any action the Director determines to be necessary and reasonable to prevent or mitigate adverse impacts on any air, water, soil, or biological resource caused by a spill or release.

(4)	Operators will document and maintain records to demonstrate compliance with the concentration levels in Table 915-1, and, if surface water or Groundwater are impacted, WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b.  

(5)	For any spills or releases that do not meet the reporting requirements of Rule 912.b, Operators will document cleanup efforts and provide documentation of the cleanup to the Director upon request.

b.	Reporting Spills or Releases of E&P Waste, Gas, or Produced Fluids.
	
(1)	Report to the Director.  Operators will submit an Initial Report of a spill or release of E&P Waste, natural gas, or produced fluids that meet any of the following criteria to the Director verbally or in writing, within 24 hours of discovery, unless otherwise specified below.

A.	A spill or release of any size that impacts or threatens to impact any Waters of the State, Public Water System, residence or occupied structure, livestock, wildlife, or publicly-maintained road;

B.	A spill or release in which 1 barrel or more of E&P Waste or produced fluids is spilled or released outside of berms or other secondary containment; 

C.	A spill or release of 5 barrels or more regardless of whether the spill or release is completely contained within berms or other secondary containment. 

D.	Within 6 hours of discovery, a Grade 1 Gas Leak. For a Grade 1 Gas Leak from a Flowline, the Operator also must submit the Form 19, COGCC Spill/Release Report, document number on a Form 44, Flowline Report for the Grade 1 Gas Leak.  

E.	A spill or release of any volume that daylights from the subsurface.

F.	The discovery of 10 cubic yards or more of impacted material resulting from a current or historic spill or release. Discovery and reporting will not be contingent upon confirmation samples demonstrating exceedance of Table 915-1 standards.

G.	The discovery of impacted Waters of the State, including Groundwater. Discovery and reporting will not be contingent upon confirmation samples demonstrating exceedance of Table 915-1 standards. The presence of free product or hydrocarbon sheen on Groundwater or surface water is reportable. The presence of contaminated soil in contact with Groundwater or surface water is reportable.

H.	A suspected or actual spill or release of any volume where the volume cannot be immediately determined.

I.	A spill or release resulting in vaporized mists that leave the Oil and Gas Location and impacts or threatens to impact off-location property.

J.	A release of natural gas that results in an accumulation of soil gas or gas seeps.

K.	A release that results in natural gas in groundwater.
 
(2)	The Initial Report to the Director will include, at a minimum,
	
A.	The specific location of the spill/release including latitude and longitude;

B.	Certification that the Operator provided additional party notifications as required by Rules 912.b.(7)–(10), below;

C.	A description of any threat to Waters of the State, Public Water System, residences or occupied structures, livestock, wildlife, air quality, or publicly-maintained road from the spill or release; and

D.	Any information available to the Operator about the type and volume of fluid or waste involved, including whether it is controlled or uncontrolled at the time of submitting the Initial Report.   

(3)	If the Operator did not submit its Initial Report through a Form 19, Spill/Release Report, the Operator will submit a Form 19 with the Initial Report information no less than 72 hours after discovery of the spill or release unless the Director extends the timeframe in writing.  

(4)	In addition to the Initial Report to the Director, the Operator will make a supplemental report on a Form 19 not more than 10 days after the spill or release is discovered that includes:

A.	A topographic map showing the governmental section and location of the spill or an aerial photograph showing the location of the specific spill site. 

B.	All pertinent information about the spill or release known to the Operator that has not been reported previously, including photo documentation showing the source of the spill or release, the impacted area, and initial cleanup activity; and

C.	Information relating to the initial mitigation, site investigation, and remediation measures conducted by the Operator.  

D.	Global Positioning System data that meets the requirements of Rule 216 if latitude and longitude data provided pursuant to Rule 912.b.(2).A did not meet the requirements of Rule 216.

(5)	The Director may require any additional supplemental reports or information the Director determines are necessary.

(6)	No later than 90 days after a spill or release is discovered, the Operator will have submitted, and obtained the Director’s approval of either:

A.	A Form 19, Spill/Release Report requesting closure pursuant to Rule 913.h and supported by adequate documentation to demonstrate that the spill or release has been fully cleaned up and complies with Table 915-1; or

B.	A Form 27, Site Investigation and Remediation Workplan if:

i.	A Form 27 is required by the Commission’s Rules;

ii.	Cleanup or remediation will continue for longer than 90 days after the spill or release was discovered; or

iii.	The Director requests a Form 27.

(7)	Notification to Local Governments.  At the same time the Operator submits an Initial Report to the Director pursuant to Rule 912.b.(1),  the Operator will provide verbal or written notification to the entity with jurisdiction over emergency response within the local municipality if the spill or release occurred within a municipality or the local county if the spill or release did not occur within a municipality. The notification will include, at a minimum, the information provided in the Initial Report to the Director.

(8)	Notification to the Surface Owner.  The Operator will provide verbal or written notification to the affected Surface Owner or the Surface Owner’s appointed tenant concurrent with providing an Initial Report to the Director pursuant to Rule 912.b.(1).

A.	If the Surface Owner cannot be reached within 24 hours, the Operator will continue to make good faith efforts to notify the Surface Owner until notice has been provided.

B.	The verbal or written notification will include, at a minimum, the information provided in the Initial Report to the Director. 

C.	The Operator will document the notification including the name of the person contacted, phone number or email of contact, date and time.  

(9)	Report to Environmental Release/Incident Report Hotline.  Operators will report a spill or release of any size which impacts or threatens to impact surface waters to the Director and to the Environmental Release/Incident Report Hotline (1-877-518-5608). Spills and releases that impact or threaten a Public Water System intake, as described in Rule 411.b, will be verbally reported to the emergency contact for that facility immediately after discovery. 

(10)	At the same time the Operator submits an Initial Report to the Director pursuant to Rule 912.b.(1), the Operator will provide verbal or written notification to Colorado Parks and Wildlife if the spill or release occurred within 300 feet of surface Waters of the State, or within High Priority Habitat.

(11)	Reporting Chemical Spills or Releases.  Operators will report chemical spills and releases pursuant to 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. 
	
c.	Remediation of Spills or Releases.

(1)	The Director may require Operators to submit a Form 27, Site Investigation and Remediation Workplan, if the Director identifies any threatened or actual adverse impacts to any air, water, soil, wildlife, or other environmental resource from a spill or release, or if necessary to ensure compliance with the concentration levels in Table 915-1 and WQCC Regulation 41 numeric and narrative Groundwater quality standards and classifications, as incorporated by reference in Rule 901.b. 

(2)	Not including initial emergency response operations, the Operator will notify and consult with any affected Surface Owners, or the Surface Owner’s appointed tenant, prior to commencing operations to remediate a spill or release in an area not being utilized for Oil and Gas Operations. It is the Operator’s burden to timely notify and negotiate access with the Surface Owner. Failure to do so will not relieve the Operator from its responsibility to commence or complete remediation approved by the Director.  
	
d.	Spill and Release Prevention.

(1)	Operators will determine and document the cause of a Grade 1 Gas Leak or spill or release of E&P Waste or produced fluids. After identifying the cause, Operators will implement measures to prevent spills or releases due to similar causes in the future, and document all changes made.  

(2)	The Director may take enforcement action if a spill occurs at any site subject to control of the same Operator as a result of similar causes identified in Rule 912.d.(1). 

(3)	Operators will provide documentation of the spill or release evaluation and any steps taken to prevent spills or releases due to similar causes in the future to the Director upon request.

e.	Suspected Spill or Release Closure.

(1)	Operators will submit a Supplemental Form 19, Spill/Release Report providing documentation that any suspected spill or release reported pursuant to Rule 912.b.(1).H. did not exceed any applicable reporting thresholds. The Operator will clean up any actual spill below the reporting threshold of Rule 912.b pursuant to the requirements of Rule 912.a.(5).

(2)	If the suspected spill or release reported pursuant to Rule 912.b.(1).H did in fact exceed any reporting threshold identified in Rule 912.b.(1), the Operator will clean up the spill pursuant to the requirements of Rule 912.c.

f.	Changes of Operator.  Pursuant to Rule 218.a.(3), upon the Director’s approval of a Form 9, Transfer of Permits, a new Operator will submit a supplemental Form 19, Spill/Release Report designating the responsible Operator for each open spill and release. 

913.	SITE INVESTIGATION, REMEDIATION, AND CLOSURE

a.	Applicability.  This Rule 913 applies to the investigation, remediation, and reporting required for spills and releases, remediation projects, and decommissioning of Oil and Gas Facilities. All site investigation, remediation, and closure operations will be conducted in accordance with the Commission’s Rules, including the Commission’s 1000 Series Rules. 

b.	General Site Investigation and Remediation Requirements.
 
(1)	Site Investigation and Remediation Workplan.  Operators will submit and obtain the Director’s approval of a Form 27, Site Investigation and Remediation Workplan whenever it is required by the Commission’s Rules, prior to commencing the operations addressed by the Form 27.

(2)	Sampling and Analyses.  Operators will conduct sampling and analysis of soil and Groundwater pursuant to Rule 915 to determine the horizontal and vertical extent of any contamination in excess of the cleanup concentrations in Table 915-1 or in WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b. 

A.	Sampling and analyses will be required to profile E&P Waste, delineate extent of contamination, and confirm compliance with applicable standards upon completion of remediation.

B.	Laboratory method detection limits must be less than or equal to Table 915-1 or WQCC Regulation 41 standards, as incorporated by reference in Rule 901.b.

C.	Composite sample results may be submitted for preliminary analysis and waste profiling. Discrete sample results will be required for confirmation sampling.

(3)	Management of Investigation-Derived Waste.  Investigation-Derived waste will be managed pursuant to Rules 905 or 906.

(4)	Pit Evacuation.  Prior to site investigation and remediation, E&P Waste will be treated or disposed pursuant to Rule 905. 

(5)	Remediation. 

A.	Remediation will be performed in a manner that reduces or removes contamination that exceeds the cleanup concentrations in Table 915-1 or in WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b, and that protects and mitigates adverse impacts to public health, safety, welfare, the environment, and wildlife resources. 

B.	When conducting remediation activities, Operators will conform to the following standards:

i.	Operators will fence open excavations to prevent access when sites are not attended.

ii.	Operators will protect topsoil, consistent with the Commission’s 1000 Series Rules.

iii.	Operators will minimize surface disturbance.

iv.	Operators will properly store, handle, and manage all E&P Waste to prevent contamination of stormwater, surface water, Groundwater, and soil.

v.	If remediation occurs within High Priority Habitat, the Operator will incorporate Best Management Practices protective of the relevant wildlife species or habitat in the Operator’s Form 27, Site Investigation and Remediation Work Plan.  

C.	Groundwater that does not meet the cleanup concentrations in Table 915-1 or WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b, will be remediated pursuant to a Form 27, Site Investigation and Remediation Workplan. 

(6)	Surface Reclamation.  If the Director approves the closure of a remediation project, the Operator will reclaim the site(s) pursuant to the Commission’s 1000 Series Rules. 

c.	Form 27, Site Investigation and Remediation Workplan.  Operators will prepare and obtain the Director’s approval of a Form 27, Site Investigation and Remediation Workplan, prior to conducting the following operations and remediation activities:

(1)	Pit or Cuttings Trench closure;

(2)	Buried or partially buried vessel closure, which will be by removal;

(3)	Remediation of spills and releases pursuant to Rule 912;

(4)	Land Treatment of Oily Waste pursuant to Rule 905.e;

(5)	Closure of Centralized E&P Waste Management Facilities pursuant to Rule 907.h;

(6)	Remediation of impacted Groundwater pursuant to Rule 915.e.(4).D, and the contaminant concentrations in Table 915-1;

(7)	Investigation and remediation of natural gas in soil or groundwater;

(8)	When requested by the Director due to any potential risk to soil, Groundwater, or surface water; and

(9)	Decommissioning of Oil and Gas Facilities.
  
d.	Implementation Schedule. Each Form 27, Site Investigation and Remediation Workplan will include a specific implementation schedule to complete investigation and remediation.  

(1)	Operators will immediately investigate impacts to soil, Groundwater and surface water.

(2)	Any change from the approved implementation schedule will be requested at least 14 days in advance, and the Operator may not make the change without the Director’s approval.  

e.	Reporting Schedule. After initial approval of a Form 27, Site Investigation and Remediation Workplan, the Operator will provide quarterly update reports in a Supplemental Form 27 to document progress of site investigation and remediation, unless an alternative reporting schedule has been requested by the Operator and approved by the Director. The Director may request a more frequent reporting schedule based on site-specific conditions.

(1)	Operators may not change the reporting schedule without the Director’s approval.

(2)	By February 2, 2021, Operators of existing remediation projects approved prior to November 2, 2020 will submit a Supplemental Form 27 with a detailed project summary and status.

(3)	For existing remediation projects approved prior to November 2, 2020, the Operator will adopt a quarterly reporting schedule unless a more frequent or specific reporting schedule was already approved by the Director. 

f.	Discovery of a Spill or Release During Closure.  If a spill or release is discovered during facility closure operations, the Operator will report it to the Director on a Form 19, Spill or Release Report, pursuant to Rule 912.

g.	Changes of Operator.  Pursuant to Rule 218.a.(3), upon the Director’s approval of a Form 9, Transfer of Permits, a new Operator will submit a supplemental Form 27 designating the responsible Operator for all open remediation projects. 

h.	Closure.

(1)	Remediation will be considered complete when the Operator has demonstrated compliance with: 

A.	The cleanup concentrations in Table 915-1;

B.	WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b, if applicable; and

C.	Any condition of approval of a Form 27, Site Investigation and Remediation Workplan.
	
(2)	An Operator may request the Director’s approval of a variance through Rule 502.a to comply with an alternative standard in lieu of one or more of the standards in Rule 913.h.(1).A–C. In addition to applying for a variance, the Operator will also submit a Form 27 demonstrating that their alternative clean-up process protects and minimizes adverse impacts to public health, safety, welfare, the environment, and wildlife resources.

(3)	For contaminated groundwater where periodic monitoring has been required, closure may not occur until after 4 consecutive quarters of sampling and analysis demonstrating compliance with Table 915-1 and WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b, if applicable. 

(4)	Notification of Completion.  Within 30 days after conclusion of site remediation activities:

A.	Operators conducting remediation operations pursuant to an approved Form 27, Site Investigation and Remediation Workplan will submit to the Director a Supplemental Form 27 containing documentation sufficient to demonstrate compliance with the Commission’s Rules.

B.	Operators will coordinate with the Director through a Form 4, Sundry Notice regarding additional surface reclamation required by the Commission’s 1000 Series Rules, if applicable.

i.	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.

914.	CRITERIA TO ESTABLISH POINTS OF COMPLIANCE.  In determining a Point of Compliance, the Director will take into consideration recommendations of the Operator or any responsible party or parties, if applicable, together with the following factors:

a.	The classified use established by the Water Quality Control Commission, for any Groundwater or surface water that was impacted by contamination. If not so classified, the Director will 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 hydraulic conductivity, soil types, surface water impacts, and any seasonal hydrologic variability;

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;

f.	The distance to the nearest permitted domestic water well or Public Water System supply well completed in the same aquifer affected by the event; and

g.	The distance to the nearest permitted livestock or irrigation water well completed in the same aquifer affected by the event.

915.	CONCENTRATIONS AND SAMPLING FOR SOIL AND GROUNDWATER.  

a.	Soil Concentrations.  Operators will adhere to the concentrations for soil cleanup in Table 915-1. Operators will use Residential Soil Screening Level Concentrations as cleanup levels unless required otherwise by the Director.  The Director will require adherence to the Protection of Groundwater Soil Screening Levels when a pathway to groundwater exists. When the Director has reasonable cause to believe that oil and gas exploration-related compounds or parameters other than those listed in Table 915-1 may be present, the Director may require additional analyses of compounds included in the EPA RSLs, as incorporated by reference in Rule 901.b.

b.	Soil Suitability for Reclamation.  Operators will adhere to the concentrations for soil in Table 915-1 for restoring soil to the agronomic properties for electrical conductivity (EC), sodium adsorption ratio (SAR), pH, and boron for soils. Subject to prior approval by the Director, Operators may leave materials with elevated concentrations of EC, SAR, or pH in situ. In such cases, the Operator will provide a detailed reclamation plan that includes, but is not limited to, soil analysis from adjacent undisturbed lands, revegetation techniques, site stabilization, and details of seeded species. 

c.	Groundwater Concentrations.  Operators will adhere to the concentrations for Groundwater in Table 915-1. The Groundwater standards and analytical methods are derived from the Groundwater standards and classifications established by WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b.

d.	Additional Groundwater Analyses.  When the Director has reasonable cause to believe that oil and gas exploration-related compounds or parameters other than those listed in Table 915-1 may be present, the Director may require additional analyses beyond the list of compounds included in Table 915-1 for Groundwater including but not limited to:

(1)	Any element, compound or parameter listed in Table A and Tables 1, 2, 3, and 4 of WQCC Regulation 41, as incorporated by reference in Rule 901.b.

(2)	In accordance with the Narrative Standards of WQCC Regulation 41.5.A, any element, compound, or parameter not listed in Table A or Tables 1, 2, 3, and 4 of WQCC Regulation 41, as incorporated by reference in Rule 901.b, which alone or in combination with other substances, are in concentrations shown to be:

A.	Carcinogenic, mutagenic, teratogenic, or toxic to human beings; or,

B.	A danger to public health, safety, and welfare.

e.	Sampling and Analysis.  Analysis will be conducted using EPA SW-846 analytical methods, as incorporated by reference in Rule 901.b, or, with the Director’s approval, other analytical methods published by nationally-recognized organizations. Analyses of samples will be performed by laboratories that maintain state or national accreditation programs. The use of specialized and appropriate agricultural analytical methods are recommended for analysis of the Soil Suitability parameters, and are required as partially described in footnote 2 to Table 915-1.

(1)	Methods for Sampling and Analysis.  Sampling and analysis for site investigation or confirmation of successful remediation will be conducted to determine the nature and extent of impact and confirm compliance with appropriate concentration levels in Table 915-1 and WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b. 

A.	Field Analysis.  Field measurements and field tests will be conducted using appropriate equipment, calibrated and operated according to manufacturer specifications, by personnel trained and familiar with the equipment. Operators will provide all field measurements and tests to the Director upon request, including but not limited to field notes, field screening logs, soil boring logs, monitor well construction logs, pump test reports, photographs, and soil vapor screening results.

B.	Sample Collection.  Samples will be collected, preserved, documented, and shipped or delivered to a laboratory under a chain-of-custody protocol using standard environmental sampling procedures in a manner to ensure accurate representation of site conditions.

C.	Laboratory Analytical Methods. Laboratories will analyze samples using standard methods (including but not limited to EPA SW-846, as incorporated by reference in Rule 901.b) appropriate for detecting the target analyte. The method selected will have detection limits less than or equal to the cleanup concentrations in Table 915-1 and WQCC Regulation 41, as incorporated by reference in Rule 901.b.

D.	Background Sampling.  The Director may require the Operator to take site-specific samples, outside of the area disturbed by oil and gas operations, of comparable, nearby, non-impacted, native soil, Groundwater or other media to establish background conditions.

(2)	Soil Sampling and Analysis.

A.	Applicability.  If soil contamination is suspected or known to exist as a result of spills or releases or E&P Waste management, Operators will collect and analyze representative samples of soil pursuant to this Rule 915.e.(3).

B.	Sample Collection.  Samples will be collected from areas most likely to have been impacted, and the horizontal and vertical extent of contamination will be determined. The number and location of samples will be appropriate to determine the horizontal and vertical extent of the impact.

C.	Sample Analysis.  Operators will analyze soil samples for contaminants of concern listed in Table 915-1 as appropriate to assess the impact or confirm remediation. If an Operator believes it is appropriate to modify the list of contaminants of concern, the Operator will submit, and obtain the Director’s approval of, a modified list of contaminants of concern through a Form 19, Spill/Release Report, or Form 27, Site Investigation and Remediation Workplan, as applicable. The list will be based on site specific E&P Waste profile and process knowledge. Operators will analyze samples for additional contaminants of concern upon the Director’s request.

D.	Soil Background Determination.  For impacts to soil due to E&P Waste, samples from comparable, nearby non-impacted native soil will be collected and analyzed for purposes of establishing background soil conditions including pH, electrical conductivity (EC), sodium adsorption ratio (SAR), and other constituents as identified in the E&P Waste profile. 

(3)	Groundwater Sampling and Analysis.

A.	Applicability.  Operators will collect and analyze representative samples of Groundwater if:

i.	Groundwater contamination is suspected or is known to exceed the concentrations in cleanup Table 915-1 or WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b;

ii.	Impacted soils are in contact with Groundwater; or

iii.	Impacts to soils extend down to the high water table.
  
B.	Sample Collection.  Operators will collect samples as soon as possible from areas most likely to have been impacted: immediately downgradient or in the middle of excavated areas in close proximity to the suspected source of the impact.

i.	The number and location of samples will be appropriate to determine the horizontal and vertical extent of the impact.

ii.	If the cleanup concentrations in Table 915-1 or WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b, are exceeded, the direction of flow and a ground water gradient will be established.

iii.	The Director may require the installation of temporary or permanent monitoring wells as necessary for sample collection. All monitoring wells will be constructed and permitted in accordance with the State Engineer’s Water Well Construction and Permitting Rules, as incorporated by reference in Rule 901.b.

C.	Sample Analysis.  Operators will analyze groundwater samples for constituents of concern listed in Table 915-1, or other parameters appropriate for evaluating the impact, to assess the impact or confirm remediation. If an Operator believes it is appropriate to modify the list of constituents of concern, the Operator will submit, and obtain the Director’s approval of, a modified  list of constituents of concern through a Form 19, Spill/Release Report, or Form 27, Site Investigation and Remediation Workplan, as applicable. The list will be based on site specific E&P Waste profile and process knowledge. Operators will analyze samples for additional constituents of concern upon the Director’s request.

D.	Impacted Groundwater.  Pursuant to Rule 913.c.(6), if Groundwater contaminants exceed the concentrations listed in Table 915-1 or in WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b, Operators will notify the Director and submit to the Director for prior approval a Form 27, Site Investigation and Remediation Workplan, for the investigation, remediation, or monitoring of Groundwater to meet the required cleanup concentrations in Table 915-1 or in WQCC Regulation 41 numeric and narrative groundwater quality standards and classifications, as incorporated by reference in Rule 901.b.

(4)	Waste and Produced Fluids Sampling and Analysis.  When required by the Director, Operators will collect samples necessary to adequately characterize the composition of produced oil, condensate, water, drilling fluids, drill cuttings, production gases, bradenhead gases, soil gas, and soil gas seeps. The Operator will submit, and obtain the Director’s approval of the number of samples collected, the analyte lists, and analytical methods appropriate to the waste or production stream.

f.	Remediations in Progress.  For sites that are subject to an open Form 19, Spill/Release Report or Form 27, Site Investigation and Remediation Workplan as of November 2, 2020, Operators may seek the Director’s permission to comply with the version of Table 910-1 that was in effect November 2, 2020, if remediation is completed by November 2, 2021.  If remediation at a site subject to an open Form 19 or Form 27 is not completed by November 2, 2021, then the Operator will comply with the current version of Table 915-1.

Table 915-1
CLEANUP CONCENTRATIONS

Contaminant of Concern	Concentrations	
Soil TPH (total volatile [C6-C10] and extractable [C10-C36] hydrocarbons)	500mg/kg	
Soils and Groundwater - liquid hydrocarbons including condensate and oil 	below visual detection limits	
Soil Suitability for Reclamation	
Electrical conductivity (EC) (by saturated paste method)1,2	<4mmhos/cm	
Sodium adsorption ratio (SAR) (by saturated paste method)1,2,3	<6	
pH (by saturated paste method)1,2 	6–8.3	
boron (hot water soluble soil extract)1,3	2mg/l	
Organic Compounds in Groundwater4	
benzene	5µg/l	
toluene5	560 to 1,000µg/l	
ethylbenzene	700µg/l	
xylenes (sum of o-, m- and p- isomers = total xylenes)5	1,400 to 10,000µg/l	
naphthalene	140µg/l	
1,2,4-trimethylbenzene	7µg/l	
1,3,5-trimethylbenzene	7µg/l	
 Groundwater Inorganic Parameters4	
total dissolved solids (TDS)1	<1.25 X local background	
chloride ion1	250mg/l or <1.25 X local background	
sulfate ion1	250mg/l or <1.25 X local background	

Table 915-1 (continued)
Contaminant of Concern	Concentrations	
 	Residential Soil Screening Level Concentrations (mg/kg)7	Protection of Groundwater Soil Screening Level Concentrations (mg/kg) Risk Based (R) and MCL Based (M)7,8	
Organic Compounds in Soils6	
benzene	1.2	0.0026 (M) 	
toluene	490	0.69 (M) 	
ethylbenzene	5.8	0.78 (M) 	
xylenes (sum of o-, m- and p- isomers = total xylenes)	58	9.9 (M)	
1,2,4-trimethylbenzene	30	0.0081 (R) 	
1,3,5-trimethylbenzene	27	0.0087 (R) 	
acenaphthene	360	0.55 (R)	
anthracene	1800	5.8 (R)	
benz(a)anthracene	1.1	0.011 (R)	
benzo(b)fluoranthene	1.1	0.3 (R)	
benzo(k)fluoranthene	11	2.9 (R)	
benzo(a)pyrene	0.11	0.24 (M)	
chrysene	110	9 (R)	
dibenzo(a,h)anthracene	0.11	0.096 (R)	
fluoranthene	240	8.9 (R)	
fluorene	240	0.54 (R)	
indeno(1,2,3-cd)pyrene	1.1	0.98 (R)  	
1-methylnaphthalene	18	0.006 (R)  	
2-methylnaphthalene	24	0.019 (R)	
naphthalene	38	0.00054 (R)	
pyrene	180	1.3 (R)	
Metals in Soils 1, 6	
arsenic	0.68 or <1.25 X local background	0.29 (M)	
barium	1500	82 (M)	
cadmium	7.1	0.38 (M)	
chromium (VI)	0.3	0.00067 (R)	
copper	310	46 (M)	
lead	400	14 (M)	
nickel	150	2.6 (R)	
selenium	39	0.26 (M)	
silver	39	0.08 (R)	
zinc	2300	37 (R)	

Table 915-1 (continued) footnotes

1 The Director will consider adjacent background concentrations or reference levels in native soils and Groundwater.

2 Soil suitability thresholds for electrical conductivity (EC), pH and sodium adsorption ratio (SAR) in soils are based on use of saturated paste preparation methods, followed by analysis. Soil suitability thresholds for available boron are based on hot water soluble (or DPTA/sorbitol) extraction followed by analysis. Methods for preparation and analysis of the soil suitability parameters can be found in Soil, Plant, and Water Reference Methods for the Western Region, as incorporated by reference in Rule 901.b.

3  With the Director’s prior approval, SAR levels and the concentration for hot water soluble boron may be modified based on land use, depth, or characteristics of the vegetative community. 

4  Concentrations for Groundwater are taken from WQCC Regulation 41, as incorporated by reference in Rule 901.b. 
 
5 For toluene and xylenes (total), 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 will be no more restrictive than the second number in the range or the groundwater 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 will apply instead of these statewide standards. 

6  Concentrations for organic compounds and metals in soils are taken from EPA Regional Screening Levels (“EPA RSLs”) for Chemical Contaminants at Superfund Sites, as incorporated by reference in Rule 901.b.  

7  If there is no pathway for communication with Groundwater, then Residential Soil Screening Levels apply for organic compounds and metals. If the Director determines that a pathway to Groundwater exists, then the Protection of Groundwater Soil Screening Levels will apply, secondary to actual measured concentrations of the contaminants of concern in Groundwater

8 (R) indicates that following a Protection of Groundwater soil screening levels indicates concentration derived from risk based approach. (M) indicates that, following a Protection of Groundwater soil screening levels indicates concentration derived drinking water maximum contaminant levels (MCL).
DEFINITIONS
100 SERIES
AVOID ADVERSE IMPACTS means to differentially select alternative locations, practices or methods for Oil and Gas Operations based on site-specific circumstances, so that those operations will not cause quantifiable direct, indirect, or cumulative adverse impacts to the potentially affected resource(s).
COMPENSATORY MITIGATION PLAN means a plan submitted pursuant to Rule 1203.b to offset the direct and unavoidable adverse indirect impacts to wildlife resources from Oil and Gas Operations. A Compensatory Mitigation Plan may be one component of a Wildlife Mitigation Plan submitted pursuant to Rules 304.c.(17) and 1201.b.
HIGH PRIORITY HABITAT means habitat areas identified by Colorado Parks and Wildlife where measures to avoid, minimize, and mitigate impacts to wildlife have been identified to protect breeding, nesting, foraging, migrating, or other uses by wildlife. 
MINIMIZE ADVERSE IMPACTS means, as provided by § 34-60-106(2.5), C.R.S., providing necessary and reasonable protections to reduce the extent, severity, significance, or duration of unavoidable direct, indirect, and cumulative adverse impacts to public health, safety, welfare, the environment, or wildlife resources from Oil and Gas Operations.
MITIGATE ADVERSE IMPACTS means, with respect to wildlife resources, measures that compensate for unavoidable direct, indirect, and cumulative adverse impacts and loss of such resources from Oil and Gas Operations, including, as appropriate, habitat replacement, on- or off-site habitat enhancement, habitat banking, or financial payment in lieu of habitat replacement or enhancement to compensate for the loss of habitat and ensure that wildlife populations are protected.
UNAVOIDABLE ADVERSE IMPACTS means direct, indirect, or cumulative adverse impacts to public health, safety, welfare, the environment, or wildlife resources that are not entirely eliminated through the application of alternative location selection or other methods designed to minimize adverse impacts from Oil and Gas Operations. 
WILDLIFE MITIGATION PLAN means a document submitted pursuant to Rules 304.c.(17) and 1201.b for an Oil and Gas Location within High Priority Habitat that describes the implementation of operating requirements pursuant to Rules 1202.a, 1202.b and 1202.c, as well as any mitigation requirements pursuant to Rules 1202.d. and 1203. A Compensatory Mitigation Plan to offset the direct and unavoidable adverse indirect impacts to wildlife resources pursuant to Rule 1203.b may be a component of the Wildlife Mitigation Plan.
WILDLIFE PROTECTION PLAN means a document submitted pursuant to Rules 304.c.(17) and 1201.a for Oil and Gas Locations outside of High Priority Habitat that describes the implementation of operating requirements pursuant to Rule 1202.a at the proposed Oil and Gas Location.
WILDLIFE RESOURCES means fish, wildlife, and their aquatic and terrestrial habitats used for all life stages, including reproduction, rearing of young and foraging, and the migration corridors and seasonal ranges necessary to sustain robust wildlife populations.

PERMITTING PROCESS
300 SERIES
[Rest of 300 Series Omitted]
304.	FORM 2A: OIL AND GAS LOCATION ASSESSMENT APPLICATION
b.	Information Requirements.  All Form 2A, Oil and Gas Location Assessments Applications must include the following information:
(2)	Alternative Location Analysis.
A.	Applicability:  This Rule 304.b.(2) applies to any proposed Oil and Gas Location that does not meet the criteria of Rule 302.b.(2), and meets one or more of the following criteria: 

iv.	The proposed Oil and Gas Location is within High Priority Habitat and the applicant did not obtain a waiver from Colorado Parks and Wildlife through a pre-application consultation; or
309.	CONSULTATION
e.	Colorado Parks and Wildlife.
(1)	The Purpose of Consultation.  The purpose of consultation with Colorado Parks and Wildlife (CPW) is to provide the Director the information necessary to determine whether conditions of approval are necessary to avoid, minimize, or mitigate adverse impacts to wildlife resources associated with High Priority Habitats, and protect against adverse impacts to wildlife resources resulting from Oil and Gas Operations. Factors that CPW may take into consideration during consultation include, but are not limited to, the following:
A.	Anticipated direct and indirect effects of the proposed Oil and Gas Operations on wildlife resources;
B.	The extent to which the proposed siting of facilities avoids or minimizes impacts;
C.	The extent to which the proposed Oil and Gas Operations incorporate the use of existing facilities, roads, and pipeline corridors and limit new surface disturbance and habitat fragmentation;
D.	The extent to which the proposed Oil and Gas Operations use technology and Best Management Practices which are protective of wildlife resources, including but not limited to seasonal construction and drilling limitations, noise limitations, remote operations, equipment disinfection, and transporting and storing liquids through pipelines and large tanks or other measures to reduce traffic volumes; and
E.	The extent to which the proposed Oil and Gas Operations are within land used or designated to be used for residential, industrial, commercial, agricultural, or other purposes, and the existing wildlife disturbance associated with such use. 
(2)	When Consultation Must Occur. The Operator will consult with the Surface Owner (unless the Surface Owner has waived their right to participate pursuant to 309.e.(3).C) and with CPW about a Form 2A, Oil and Gas Location Assessment, Oil and Gas Development Plan, Comprehensive Area Plan, or other matter where:
A.	 A proposed Oil and Gas Location or associated new access road, utility, or pipeline corridor falls within High Priority Habitat, a State Park, or a State Wildlife Area.
B.	A proposed Oil and Gas Location or associated new access road, utility, or pipeline corridor falls within federally designated Critical Habitat for a Threatened or Endangered species. 
C.	A proposed Oil and Gas Location or associated new access road, utility, or pipeline corridor falls within an existing conservation easement established wholly or partly for wildlife habitat.
D.	CPW requests consultation or because consultation is necessary to avoid, minimize, or mitigate reasonably foreseeable  direct, indirect, or cumulative adverse impacts to wildlife resources from a Form 2A, Oil and Gas Location Assessment, Oil and Gas Development Plan, Comprehensive Area Plan, or other matter where consultation is not otherwise required.
E.	The Operator seeks a variance from a provision in the Commission’s 1200 Series Rules, or from wildlife-specific conditions of approval or Best Management Practices approved on a Form 2A, Oil and Gas Location Assessment. 
F.	The Director determines that consultation would assist the Director in determining whether to recommend approving or denying an Oil and Gas Development Plan or Comprehensive Area Plan.
G.	Notwithstanding the foregoing, the requirement to consult with CPW may be waived by CPW at any time. Any waiver will be based on a written finding by CPW that consultation is not necessary to protect wildlife resources from quantifiable adverse direct, indirect, or cumulative impacts from Oil and Gas Operations.
(3)	When Consultation is Not Required.  Consultation will not be required if:
A.	The Director has previously approved a Form 2A, Oil and Gas Location Assessment or Comprehensive Area Plan and associated Wildlife Protection Plan or Wildlife Mitigation Plan that addresses the proposed new Oil and Gas Location and the proposed operations are in compliance with previously approved plans.
B.	CPW has previously approved, in writing, a Wildlife Protection Plan, Wildlife Mitigation Plan, or other conservation plan that remains in effect for the area that includes the proposed new Oil and Gas Location and the proposed operations are in compliance with such plan.
C.	The Operator demonstrates and CPW agrees in writing that: 
i.	The identified habitat and/or species triggering the consultation is no longer present and unlikely to return to the area; and 
ii.	The proposed Oil and Gas Location is within an area either primarily or completely developed for residential, agricultural, commercial, or industrial use that makes the area incompatible with wildlife habitat.
D.	The proposed new Oil and Gas Location would involve a one-time increase in surface disturbance of 1 acre or less contiguous with an existing Oil and Gas Location with a Wildlife Mitigation Plan or other conservation plan that remains in effect for the area.
E.	A Commission Order limits the density of Oil and Gas Locations within a Drilling and Spacing Unit to 1 per section, and the Order includes a Wildlife Mitigation Plan or other conservation plan that remains in effect for the area.
(4)	Procedures for Consultation. 
A.	The Operator will provide: 
i.	The Oil and Gas Development Plan or Comprehensive Area Plan, if applicable, or for consultations that do not involve an Oil and Gas Development Plan or Comprehensive Area Plan, a description of the proposed Oil and Gas Operations, including their location and the phasing and duration of operations consistent with Rules 303 and 304, and, if applicable Rule 314; and
ii.	Any other relevant available information about the proposed Oil and Gas Operations and the affected wildlife resources, including the Wildlife Habitat Drawing pursuant to Rule 304.b.(7).C and information required by Rule 1201.
B.	The Operator, the Director, the Surface Owner, and CPW will have 60 days to conduct the consultation required by this Rule 309.e. The time period for consultation will begin concurrent with the start of the public comment period on an Oil and Gas Development Plan or Comprehensive Area Plan pursuant to Rule 303.d.(1).A. If the Operator has made no reasonable accommodation for consultation within such 60-day period, the Director will have discretion to postpone making a decision about an Oil and Gas Development Plan or Comprehensive Area Plan in order to allow consultation to occur if the Director believes the information from consultation is necessary to determine how to protect and avoid, mitigate, and minimize adverse impacts to wildlife resources. 
C.	The Surface Owner may waive its right to participate in the consultation and is not obligated to provide access to its surface for such consultation. If access to the surface is not granted, the Operator will arrange a consultation meeting with CPW at a mutually agreeable time and location and the consultation will be based on best available data.
(5)	Result of Consultation.
A.	As a result of consultation required by this Rule 309.e, CPW may make written recommendations to the Director about conditions of approval that are necessary and reasonable to avoid, minimize, or mitigate direct, indirect, and cumulative adverse impacts to wildlife resources from Oil and Gas Operations as set forth in Rules 1202 and 1203. 
B.	CPW may also recommend that the Commission deny an Oil and Gas Development Plan, Wildlife Protection Plan, Wildlife Mitigation Plan, Compensatory Mitigation Plan or Comprehensive Area Plan due to reasonably foreseeable risks to wildlife resources that cannot be avoided, minimized, or mitigated to the extent necessary to protect these resources from Oil and Gas Operations.
C.	Where applicable, CPW may also make written recommendations on whether a variance request should be granted, under what conditions, and the reasons for any such recommendations.
D.	CPW may also waive, in writing, any operating or mitigation requirements otherwise required by Rules 1202 or 1203 based on CPW’s analysis of potential unavoidable adverse impacts. 
(6)	Conditions of Approval.
A.	If the Director agrees that the conditions of approval recommended by CPW are necessary and reasonable to avoid, minimize, or mitigate adverse impacts to wildlife resources, the Director will incorporate CPW’s recommended conditions into the Director’s Recommendation on an Oil and Gas Development Plan or Comprehensive Area Plan.
B.	The Director will not incorporate conditions of approval to avoid, minimize, or mitigate adverse impacts to wildlife resources into the Director’s Recommendation without consent of the affected Surface Owner. This provision does not apply to conditions of approval to avoid, minimize, or mitigate impacts to wildlife resources that do not directly impact the affected Surface Owner’s property or use of that property including, but not limited to, off-site compensatory mitigation requirements.
C.	If the Director determines that any conditions of approval recommended by CPW are not necessary to avoid, minimize, or mitigate adverse impacts to wildlife resources, the Director will explain the grounds for the disagreement in the Director’s Recommendation.
D.	The Commission will determine whether to follow CPW’s recommendation when making a final decision to approve or deny an Oil and Gas Development Plan or Comprehensive Area Plan.
(7)	Notification of Decision to Consulting Agency.  Pursuant to Rule 306.c.(6), if consultation occurred under this Rule 309.e, the Director will provide the Director’s Recommendation to CPW on the same day that it announces the decision. CPW may petition the Director’s Recommendation before the Commission pursuant to Rule 507.c.

RULES OF PRACTICE AND PROCEDURE
500 SERIES
[Rest of 500 Series Omitted]

529.	RULEMAKING PROCEEDINGS

d.	Development of Proposed Rules.  Prior to the notice of proposed rulemaking, the Commission or Director will establish a representative group of participants with an interest in the subject of the rulemaking as provided by § 24-4-103(2), C.R.S. The Commission or Director may also use other means 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.

(1)	Colorado Parks and Wildlife Consultation.  For new basin-wide orders or modifications of existing basin-wide or field-wide orders, on issues pertaining to wildlife resources or wildlife-related environmental concerns or protections, or for development acreage that intersects High Priority Habitat, the Commission will consult with Colorado Parks and Wildlife during the stakeholder process.

PROTECTION OF WILDLIFE RESOURCES
1200 SERIES
1201.	WILDLIFE PLANS 

a.	Wildlife Protection Plan. Proposed Oil and Gas Operations on new or amended Oil and Gas Locations outside of High Priority Habitat require a Wildlife Protection Plan that includes a description of the Rule 1202.a operating requirements applicable to the Oil and Gas Location. Wildlife Protection Plans may address multiple Oil and Gas Locations if supplemental site-specific information is provided as needed to meet Rule 1202.a operating requirements at each Oil and Gas Location. Wildlife Protection Plans do not require Colorado Parks and Wildlife (CPW) consultation or approval.

b.	Wildlife Mitigation Plan. Proposed Oil and Gas Operations on new or amended Oil and Gas Locations within High Priority Habitat require a Wildlife Mitigation Plan that includes a description of the Rule 1202.a operating requirements, and the additional operating and mitigation requirements in Rules 1201.b.(1)–(4), 1202, and 1203. Wildlife Mitigation Plans may address one or multiple Oil and Gas Locations. Pre-existing CPW-approved Wildlife Mitigation Plans in effect [on November 2, 2020] may meet these requirements subject to written concurrence from CPW that the Wildlife Mitigation Plan satisfies the requirements of this Rule 1201.b.

(1)	A description of any pre-application consultation with CPW, which may include an Alternative Location Analysis pursuant to Rule 304.b.(2).A.iv, or identifying site-specific measures to avoid, minimize, or mitigate adverse impacts to wildlife resources;

(2)	A description of Best Management Practices incorporated into the proposed Oil and Gas Operations that the Operator commits to implementing for the purposes of minimizing impacts to wildlife;

(3)	A description of the Rule 1202.b operating requirements applicable to the Oil and Gas Location; and

(4)	A description of the Rule 1203 mitigation commitments to offset unavoidable adverse impacts to wildlife resources. 
1202.	OPERATING REQUIREMENTS.
a.	The operating requirements identified below apply statewide unless the Operator obtains a signed waiver from Colorado Parks and Wildlife (CPW) and following approval of a Form 4, Sundry Notice or Form 2A, Oil and Gas Location Assessment documenting the relief.

(1)	In black bear habitat, Operators will install and utilize bear-proof dumpsters and trash receptacles for food-related trash at all facilities that generate trash.

(2)	Operators will disinfect water suction hoses and water transportation tanks withdrawing from or discharging into surface waters (other than contained pits) used previously in another river, intermittent or perennial stream, lake, pond, or wetland and discard rinse water in an approved disposal facility. Disinfection practices will be repeated prior to completing work and before moving to the next water body. Disinfection will be performed by scrubbing and pre-rinsing equipment away from water bodies to remove all mud, plants, and organic materials and then by implementing one of the following practices:

A.	Spray/soak equipment with a CPW-approved disinfectant solution capable of killing whirling disease spores and other Aquatic Nuisance Species (ANS) defined by CPW; or

B.	Spray/soak equipment with water greater than 140° F for at least 10 minutes. All equipment and any compartments they contain will be completely drained and dried between each use.

(3)	At new and existing Oil and Gas Locations, Operators will not situate new staging, refueling, or chemical storage areas within 300 feet of the Ordinary High Water Mark (OHWM) of any river, perennial or intermittent stream, lake, pond, or wetland.

(4)	To prevent access by wildlife, including birds and bats, Operators will fence and net or install other CPW-approved exclusion devices on new and existing Drilling Pits, Production Pits, and other Pits associated with Oil and Gas Operations that are intended to contain fluids. Such fencing and netting or other CPW-approved exclusion device will be installed within 5 days after the cessation of active drilling and completion activities and maintained until removed. Fencing, netting or other exclusion devices will be removed when the Pit is removed from service and dried or closed pursuant to the Commission’s 900 Series Rules.

(5)	For trenches that are left open for more than 5 consecutive days during construction of pipelines regulated under the Commission’s 1100 Series Rules, Operators will install wildlife escape ramps at a minimum of one ramp per 1/4 mile of trench.

(6)	When conducting interim and final reclamation under Rules 1003 and 1004, Operators will use CPW-recommended seed mixes for reclamation when consistent with the Surface Owner’s approval and any local soil conservation district requirements.

(7)	Operators will use CPW-recommended fence designs when consistent with the Surface Owner’s approval and any Local Government requirements.

b.	The operating requirements identified below apply to all Oil and Gas Operations in High Priority Habitats unless the Operator obtains a signed waiver from CPW and following approval of a Form 4, Sundry Notice or Form 2A, Oil and Gas Location Assessment documenting the relief.

(1)	Operators will bore, rather than trench, flowline and utility crossings of perennial streams identified as aquatic High Priority Habitat. When installing culverts or bridges, such structures will not impact or prevent the passage of fish unless otherwise directed by CPW.

(2)	Operators will treat Drilling Pits, Production Pits, and any other Pit associated with Oil and Gas Operations 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.

c.	Except as specified in Rule 1202.c.(2), below, Operators will not conduct any new ground disturbance and well work, including access road and pad construction, drilling and completion activities, and flowline/utility corridor clearing and installation activities in the High Priority Habitats listed in Rule 1202.c.(1).

(1)	High Priority Habitats subject to this Rule 1202.c include:

A.	Columbian sharp-tailed grouse (within 0.6 miles of the lek site);

B.	Greater prairie chicken (within 0.6 miles of the lek site);

C.	Greater sage-grouse (within 1.0 miles of the lek site);

D.	Gunnison sage-grouse (within 0.6 miles of the lek site);

E.	Lesser prairie chicken (within 1.25 miles of the lek site);

F.	Plains sharp-tailed grouse (within 0.4 miles of the lek site);

G.	Bald eagle (within 0.25 miles of an active nest);

H.	Ferruginous hawk (within 0.5 miles of an active nest);

I.	Golden eagle (within 0.25 miles of an active nest);

J.	Northern goshawk (within 0.5 miles of an active nest);

K.	Peregrine falcon (within 0.5 miles of an active nest);

L.	Prairie falcon (within 0.5 miles of an active nest);

M.	Swainson’s hawk (within 0.25 miles of an active nest);

N.	Least tern production area;

O.	Piping plover production area;

P.	Townsend’s big-eared bat, Mexican free-tailed bat, and myotis (within 350 feet of winter hibernacula);

Q.	Cutthroat Trout Designated Crucial Habitat (within 300 feet of OHWM);

R.	Native Aquatic Species Conservation Waters (within 300 feet of OHWM);

S.	Sportfish Management Waters (within 300 feet of OHWM); and

T.	State Wildlife Areas and State Parks.

(2)	This Rule 1202.c does not apply to:

A.	Production operations at existing Oil and Gas Locations, including:

i.	Routine maintenance, repairs and replacements of surface equipment that do not require a drilling or workover rig; 

ii.	Emergency operations;

iii.	Spill and Release response; 

iv.	Ongoing reclamation and site maintenance activities; or 

v.	Habitat improvements that have been approved by CPW or the Commission to offset adverse impacts at existing facilities.

B.	Non-emergency workovers, including uphole recompletions, plugging operations, and site investigation and remediation at existing Oil and Gas Locations, if:

i.	The Operator has obtained prior approval from the Director;

ii.	The Operator has consulted with CPW; and 

iii.	The Operator minimizes adverse impacts to the species for which the High Priority Habitat exists.

d.	All Oil and Gas Development Plans submitted after [November 2, 2020], including amendments to previously-approved Form 2As, Oil and Gas Location Assessments that cause the density of Oil and Gas Locations to exceed 1 per square mile in the High Priority Habitats listed in Rule 1202.d require a CPW-approved Wildlife Mitigation Plan pursuant to Rule 1201.b or other CPW-approved conservation plan. This Rule 1202.d applies to the following High Priority Habitat types:

(1)	Bighorn sheep migration corridors, production areas, and winter range; 

(2)	Elk migration corridors, production areas, severe winter range, and winter concentration areas;

(3)	Mule deer migration corridors, severe winter range, and winter concentration areas;

(4)	Pronghorn migration corridors and winter concentration areas;

(5)	Greater sage-grouse priority habitat management areas;

(6)	Columbian sharp-tailed grouse production areas;

(7)	Greater prairie chicken production areas;

(8)	Gunnison sage-grouse occupied habitat and production areas;

(9)	Lesser prairie chicken focal areas; and

(10)	 Plains sharp-tailed grouse production areas.
1203.	COMPENSATORY MITIGATION FOR WILDLIFE RESOURCES
a.	In High Priority Habitats listed in Rule 1202.d, the Operator will complete compensatory mitigation to offset direct and unavoidable adverse indirect impacts as specified in Rules 1203.b–d. Direct impacts to wildlife are unavoidable and occur from direct mortality or displacement during construction activities and habitat conversion to industrial facilities. Indirect impacts to wildlife occur from the cumulative functional habitat loss from fragmentation and modified habitat use as development density increases. Indirect impacts may be avoided or minimized through the application of alternative siting and Rule 1202 operating requirements. The Director, after consultation with Colorado Parks and Wildlife (CPW), will have discretion to determine whether compensatory mitigation proposed by the Operator is sufficient to protect wildlife from direct and unavoidable adverse indirect impacts. An Operator may comply with the obligation to complete compensatory mitigation by:
(1)	Completing or causing to be completed a project approved by CPW and the Director as described in a Compensatory Mitigation Plan pursuant to Rule 1203.b; or 
(2)	Paying a habitat mitigation fee to CPW, as provided by Rules 1203.c and 1203.d. Any fee per Rule 1203.c and 1203.d will be calculated to reimburse all reasonable and necessary direct and indirect costs that will be incurred by CPW in completing compensatory mitigation sufficient to offset the direct and unavoidable adverse indirect impacts to wildlife resources caused by the proposed Oil and Gas Operations.
(3)	The Director may grant an exception from the compensatory mitigation requirement set forth in this Rule 1203 after consulting with CPW pursuant to Rule 309.e.(5).
b.	If an Operator chooses to complete or cause to be completed compensatory mitigation to offset the direct and unavoidable adverse indirect impacts to wildlife resources:
(1)	The Operator will submit a Compensatory Mitigation Plan with a level of detail commensurate with the scale and scope of the impacts to the Director that includes, as appropriate:
A.	Plan objectives or mitigation goal;
B.	Coordination and concurrence with CPW;
C.	Site selection;
D.	Site protection instrument;
E.	Valuation determination;
F.	Baseline information;
G.	Mitigation schedule and workplan;
H.	Maintenance plan;
I.	Performance standards;
J.	Monitoring requirements;
K.	Long-term management plan;
L.	Adaptive management plan, if necessary;
M.	Financial assurances; and 
N.	Other information as required by the Director
(2)	The Director will consult with CPW about the adequacy of the proposed Compensatory Mitigation Plan.
(3)	The Director may accept the Operator’s Compensatory Mitigation Plan if it meets the criteria of Rule 1203.b.(1) and, in the Director’s judgment, provides adequate compensation for direct and unavoidable adverse indirect impacts to wildlife resources from the proposed Oil and Gas Operation.
c.	Direct Impact Habitat Mitigation Fee.  An Operator may comply with its obligation to mitigate direct impacts to wildlife caused by new ground disturbance within High Priority Habitat types listed in Rule 1202.d. by paying to CPW a habitat mitigation fee in the amount listed in Table 1203-1.

Table 1203-1
Direct Impact Habitat Mitigation Fee	
Total Disturbance Acres	Fee	
1.0-10.99	$13,750	
11.0+	Determined based on site-specific conditions and consultation with CPW	
d.	Indirect Impacts. 
(1)	In High Priority Habitats listed in 1202.d with a density of Oil and Gas Locations less than 5 per square mile, CPW will recommend to the Director whether compensatory mitigation is required to address the unavoidable adverse indirect impacts of habitat fragmentation caused by the proposed Oil and Gas Development Plan.  
(2)	When determining whether compensatory mitigation is required for unavoidable adverse indirect impacts, factors that CPW may consider include, but are not limited to:
A.	The existing landscape context, and extent to which the proposed Oil and Gas Operations are within land already used for residential, industrial, commercial, agricultural, or other purposes, and the existing wildlife disturbance associated with such land uses;
B.	The estimated lifespan of the proposed Oil and Gas Operations;
C.	The extent to which the proposed Oil and Gas Operations incorporate alternative siting of Oil and Gas Facilities or Oil and Gas Locations to avoid and minimize impacts;
D.	The extent to which the proposed Oil and Gas Operations incorporate the use of existing Oil and Gas Facilities and Oil and Gas Locations to limit new surface disturbance and habitat fragmentation;
E.	The extent to which the proposed Oil and Gas Operations use technology and practices which protect wildlife resources, including but not limited to:
i.	Seasonal construction and drilling limitations;
ii.	Noise limitations;
iii.	Remote operations; or
iv.	Measures to reduce traffic volumes, including but not limited to transport of liquids through the use of pipelines and storage in large tanks.
(3)	If the Director determines that compensatory mitigation for unavoidable adverse indirect impacts is necessary, the Operator may comply with its obligation to mitigate the indirect impacts of its proposed Oil and Gas Operations by either: 
A.	Choosing to complete or causing to be completed a project approved by CPW and the Director pursuant to Rule 1203.b; or
B.	By paying an additional habitat mitigation fee to CPW.
(4)	The Director will determine the amount of the fee for each proposed Oil and Gas Location based on CPW’s estimate of costs to reimburse all reasonable and necessary expenditures to complete compensatory mitigation sufficient to offset the unavoidable adverse indirect impacts to wildlife resources from the proposed disturbance.