DEFINITIONS
(100 Series)

BUILDING UNIT shall mean a Residential Building Unit; and every five thousand (5,000) square feet of building floor area in commercial facilities or every fifteen thousand (15,000) square feet of building floor area in warehouses that are operating and normally occupied during working hours.

DESIGNATED SETBACK LOCATION shall mean any Oil and Gas Location within, or proposed to be constructed within, a Buffer Zone Setback (1,000 feet), Exception Zone Setback (500 feet), within one thousand (1,000) feet of a High Occupancy Building Unit, or within three hundred fifty (350) feet of a Designated Outside Activity Area, as referenced in Rule 604. The measurement for determining any Designated Setback Location shall be made from the center of the Well or Production Facility nearest any Building Unit to the nearest wall or corner of such Building Unit.  

DESIGNATED OUTSIDE ACTIVITY AREA:  Upon Application and Hearing, the Commission, in its discretion, may establish a Designated Outside Activity Area (DOAA) for:

(i)	an outdoor venue or recreation area, such as a playground, permanent sports field,    amphitheater, or other similar place of public assembly owned or operated by a local government, which the local government seeks to have established as a Designated Outside Activity Area; or 

(ii)	an outdoor venue or recreation area, such as a playground, permanent sports field, amphitheater, or other similar place of public assembly where ingress to, or egress from the venue could be impeded in the event of an emergency condition at an Oil and Gas Location less than three hundred and fifty (350) feet from the venue due to the configuration of the venue and the number of persons known or expected to simultaneously occupy the venue on a regular basis.

The Commission shall determine whether to establish a Designated Outside Activity Area and, if so, the appropriate boundaries for the DOAA based on the totality of circumstances and consistent with the purposes of the Oil and Gas Conservation Act.  

HIGH OCCUPANCY BUILDING UNIT shall mean: 

•	any operating Public School as defined in C.R.S. § 22-7-703(4); Nonpublic School as defined in C.R.S. § 22-30.5-103.6(6.5); Nursing Facility as defined in C.R.S. § 25.5-4-103(14); Hospital; Life Care Institutions as defined in C.R.S. § 12-13-101; or Correctional Facility as defined in C.R.S. § 17-1-102(1.7), provided the facility or institution regularly serves fifty (50) or more persons; or 

•	an operating Child Care Center as defined in C.R.S. § 26-6-102(1.5).
RESIDENTIAL BUILDING UNIT means a building or structure designed for use as a place of residency by a person, a family, or families.  The term includes manufactured, mobile, and modular homes, except to the extent that any such manufactured, mobile, or modular home is intended for temporary occupancy or for business purposes.

SURFACE OWNER shall mean any person owning all or part of the surface of land upon which oil and gas operations are conducted, as shown by the tax records of the county in which the tract of land is situated, or any person with such rights under a recorded contract to purchase. 

SURFACE USE AGREEMENT shall mean any agreement in the nature of a contract or other form of document binding on the Operator, including any lease, damage agreement, waiver, local government approval or permit, or other form of agreement, which governs the operator’s activities on the surface in relation to locating a Well, Multi-Well Site, Production Facility, pipeline or any other Oil and Gas Facility that supports oil and gas development located on the Surface Owner’s property. 

URBAN MITIGATION AREA shall mean an area where: (A) At least twenty-two (22) Building Units or one (1) High Occupancy Building Unit (existing or under construction) are located within a 1,000' radius of the proposed Oil and Gas Location; or (B) At least eleven (11) Building Units or one (1) High Occupancy Building Unit (existing or under construction) are located within any semi-circle of the 1,000 radius mentioned in section (A) above.

SERIES DRILLING, DEVELOPMENT, PRODUCTION AND ABANDONMENT
303.	REQUIREMENTS FOR FORM 2, APPLICATION FOR PERMIT-TO-DRILL, DEEPEN, RE-ENTER, OR RECOMPLETE, AND OPERATE; FORM 2A, OIL AND GAS LOCATION ASSESSMENT.
a.	Form 2. APPLICATION FOR PERMIT-TO-DRILL, DEEPEN, RE-ENTER OR RECOMPLETE, AND OPERATE.
(1)	Approval by Director.  Before any person shall commence operations for the drilling or re-entry of any well, such person shall file with the Director an application on Form 2, Application for Permit-to-Drill, Deepen, Re-enter or Recomplete and Operate (Application for Permit-to-Drill), a completed (or, where it has been approved in advance, an approved) Oil and Gas Location Assessment, Form 2A, and obtain the Director's approval before commencement of operations with heavy equipment.
(2)	Operational Conflicts.  The Permit to Drill shall be binding with respect to any provision of a local governmental permit or land use approval that is in operational conflict with the Permit to Drill.
(3)	Filing Fees.  A Form 2, Application for Permit-to-Drill, shall be submitted with a filing and service fee established by the Commission (see Appendix III).  Wells drilled for stratigraphic information only shall be exempt from paying the filing and service fee.
(4)	A request to deepen, re-enter, recomplete to a different reservoir, or to drill a sidetrack of an existing well shall be filed on a Form 2, Application for Permit-to-Drill, including details of the proposed work and a wellbore diagram.
(5)	A Form 2, Application for Permit-to-Drill, shall specify the distance between the wall or corner of the nearest Building Unit and the center of the proposed Well.  
(6)	Information Requirements.  Attached to and part of the Form 2, Application for Permit-to-Drill, as filed shall be a current 8½" by 11" scaled drawing of the entire section(s) containing the proposed well location with the following minimum information:
A.	Dimensions on adjacent exterior section lines sufficient to completely describe the quarter section containing the proposed well shall be indicated. If dimensions are not field measured, state how the dimensions were determined.
B.	The latitude and longitude of the proposed well location shall be provided on the drawing with a minimum of five (5) decimal places of accuracy and precision using the North American Datum (NAD) of 1983 (e.g.; latitude 37.12345 N, longitude 104.45632 W).  If GPS technology is utilized to determine the latitude and longitude, all GPS data shall meet the requirements set forth in Rule 215. a. through h.
C.	For directional drilling into an adjacent section, that section shall also be shown on the location plat and dimensions on exterior section lines sufficient to completely describe the quarter section containing the proposed productive interval and bottom hole location shall be indicated. (Additional requirements related to directional drilling are found in Rule 321.)
D.	For irregular, partial or truncated sections, dimensions will be furnished to completely describe the entire section containing the proposed well.
E.	The field-measured distances from the nearer north/south and nearer east/west section lines shall be measured at ninety (90) degrees from said section lines to the well location and referenced on the plat. For unsurveyed land grants and other areas where an official public land survey system does not exist, the well locations shall be spotted as footages on a protracted section plat using Global Positioning System (GPS) technology and reported as latitude and longitude in accordance with Rule 215.
F.	A map legend.
		G.	A north arrow.
		H.	A scale expressed as an equivalent (e.g. - 1" = 1000').
		I.	A bar scale.
		J.	The ground elevation.
		K.	The basis of the elevation (how it was calculated or its source).
		L.	The basis of bearing or interior angles used.
M.	Complete description of monuments and/or collateral evidence found; all aliquot corners used shall be described.
N.	The legal land description by section, township, range, principal meridian, baseline and county.
		O.	Operator name.
		P.	Well name and well number.
		Q.	Date of completion of scaled drawing.
303.b.	FORM 2A, OIL AND GAS LOCATION ASSESSMENT.
(1)	Unless exempted under subsection 2, below, a completed Form 2A, Oil and Gas Location Assessment, approved by the Director or the Commission is required for:
A.	Any new Oil and Gas Location.  For purposes of this section, “new Oil and Gas Location” shall mean surface disturbance at a previously undisturbed site;
B.	Surface disturbance for purposes of modifying or expanding an existing Oil and Gas Location; or
C.	The addition of a well or a pit, except an Emergency Pit or a Flare Pit where there is no risk of condensate accumulation, to any existing Oil and Gas Location. 
(2)	Exemptions.	A new Form 2A shall not be required for the following: 
A.	Surface disturbance, other than for purposes described in subsections 303.b.(1) B and C. above, at an existing Oil and Gas Location within the originally disturbed area, even if interim reclamation has been performed; 
B.	For an Oil and Gas Location covered by an approved Comprehensive Drilling Plan and where such Comprehensive Drilling Plan contains information substantially equivalent to that which would be required for a  Form 2A for the proposed  Oil and Gas Location  and the Comprehensive Drilling Plan has been subject to procedures substantially equivalent to those required for a Form 2A, including but not limited to consultation with Surface Owners, local governments, the Colorado Department of Public Health and Environment or Colorado Parks and Wildlife, where applicable, and public notice and opportunity to comment, and where the operator does not seek a variance from the Comprehensive Drilling Plan or a provision of these rules that is not addressed in the Plan; 
C.	Gathering lines; 
D.	Seismic operations; 
E.	Pipelines for oil, gas, or water; or
F.	Roads. 
(3)	Information Requirements.  The Form 2A requires the attachment of the following information.  Where the information required under this section has been included in a federal Surface Use Plan of Operations meeting the requirements of Onshore Oil and Gas Order Number 1 (72 Fed. Reg. 10308 (March 7, 2007)), or for a federal Right of Way, Form 299, then the operator may attach the completed pertinent information and identify on the Form 2A where the information required under this section may be found therein. 
A.	A Form 2A shall specify the distance between the wall or corner of the nearest Building Unit and the center of the proposed or existing wellhead or Production Facility closest to said Building Unit.  
B.	A minimum of four (4) color photographs, one (1) of the staked location from each cardinal direction. Each photograph shall be identified by: date taken, well or location name, and direction of view.
C.	A list of major equipment components to be used in conjunction with drilling and operating the well(s), including all tanks, pits, flares, combustion equipment, separators, and other ancillary equipment and a description of any pipelines for oil, gas, or water. 
D.	A scaled drawing, or scaled aerial photograph showing the approximate outline of the Oil and Gas Location and the Well or reference point use for measuring distances.  The drawing shall include all visible improvements within five hundred (500) feet of the proposed Oil and Gas Location, with a horizontal distance and approximate bearing from Oil and Gas Location. Visible improvements shall include, but not be limited to, all Building Units, publicly maintained roads and trails, major above-ground utility lines, railroads, pipelines, mines, oil wells, gas wells, injection wells, water wells known to the operator and those registered with the Colorado State Engineer, known springs, plugged wells, known sewers with manholes, standing bodies of water, and natural channels including permanent canals and ditches through which water may flow. A description of surface uses within the five hundred (500) foot radius of a proposed Oil and Gas Location, if any, shall be attached to the scaled drawing. If there are no visible improvements within five hundred (500) feet of a proposed Oil and Gas Location, it shall be so noted on the Form 2A. 
E.	A topographic map showing all surface waters and riparian areas within one thousand (1,000) feet of the proposed Oil and Gas Location, with a horizontal distance and approximate bearing from the Oil and Gas Location. 
F.	An 8 1/2” by 11” vicinity map, U.S. Geological Survey topographic map, or scaled aerial photograph showing the access route from the highway or county road to the proposed Oil and Gas Location. 
G.	Designation of the current land use(s) and landowner’s designated final land use(s) and basis for setting reclamation standards. 
i.	If the final land use includes residential, industrial/commercial, or cropland and does not include any other uses, the land use should be indicated and no further information is needed.
ii.	If the final land use includes rangeland, forestry, recreation, or wildlife habitat, then a reference area shall be selected and the following information shall be submitted:
aa.	A topographic map showing the location of the site, and the location of the reference area; and
bb.	Four (4) color photographs of the reference area, taken during the growing season of vegetation and facing each cardinal direction. Each photograph shall be identified by date taken, well or Oil and Gas Location name, and direction of view. Provided that these photographs may be submitted at any time up to twelve (12) months after the Form 2A. 
H.	Natural Resources Conservation Service (NRCS) soil map unit description. 
I.	If the Oil and Gas Location disturbance is to occur on lands with a slope ten percent (10%) or greater, or one (1) foot of elevation gain or more in ten (10) foot distance, then the following shall be required:
i.	Construction layout drawing (construction and operation); and
ii.	Location cross-section plot (construction and operation). 
J.	If the proposed Oil and Gas Location is within one thousand (1,000) feet of a Building Unit:
i.	A scaled facility layout drawing depicting the location of all existing and proposed new Oil and Gas Facilities listed on the Form 2A; and
ii.	A Waste Management Plan describing how the Operator intends to satisfy the general requirements of Rule 907.a.; and
iii.	Evidence that Building Unit owners within the Buffer Zone received the pre-application notice required by Rule 305.a.(2)
K.	If the proposed Oil and Gas Location is within an Urban Mitigation Area, evidence that the local government received the pre-application notice required by Rule 305.a.(1).
L.	Where the proposed Oil and Gas Location is for multiple wells on a single pad, a drawing showing proposed wellbore trajectory with bottom-hole locations. 
M.	A description of any applicant-proposed Best Management Practices or, where a variance from a provision of these rules is sought, any applicant-proposed measures to meet the standards for such a variance.  With the consent of the Surface Owner, this may include mitigation measures contained in a relevant Surface Use Agreement. 
N.	If the proposed Oil and Gas Location is covered by a Comprehensive Drilling Plan accepted pursuant to Rule 216, a list of any conditions of approval. 
O.	Contact information for the Surface Owner(s) and an indication as to whether there is a Surface Use Agreement(s) or any other agreement(s) between the applicant and the Surface Owner(s) for the proposed Oil and Gas Location. 
P.	Designation of whether the proposed Oil and Gas Location is within sensitive wildlife habitat or a restricted surface occupancy area. 
Q.	If the proposed Oil and Gas Location is within a zone defined in Rule 317B, Table 1, documentation that the applicant has provided notification of the application submittal to potentially impacted public water systems within fifteen (15) stream miles downstream. 
R.	Any additional data as reasonably required by the Commission as a result of consultation with the Colorado Department of Public Health and Environment or Colorado Parks and Wildlife. 
S.	Oil and Gas Locations in wetlands.  In the event that an operator required to file a Form 2A acquires an Army Corps of Engineers permit pursuant to 33 U.S.C.A. §1342 and 1344 of the Water Pollution and Control Act (Section 404 of the federal “Clean Water Act”) for construction of an Oil and Gas Location, the operator shall so indicate on the Oil and Gas Location Assessment, Form 2A.
T.	The Operator shall indicate on the Form 2A whether it intends to seek a location exception under Rules 604.b.2 or b.3, and, if so, shall attach the relevant Surface Use Agreement(s).
303.c.	PROCESSING TIME FOR APPROVALS UNDER THIS SECTION.
(1)	In accordance with Rule 216.f.(3), where a proposed Oil and Gas Location is covered by an approved Comprehensive Drilling Plan and no variance is sought from such Plan or these rules not addressed in the Comprehensive Drilling Plan, the Director shall give priority to and approve or deny an Application for Permit-to-Drill, Form 2, or, where applicable, Oil and Gas Location Assessment, Form 2A, within thirty (30) days of a determination that such application is complete pursuant to Rule 303.h, unless significant new information is brought to the attention of the Director. 
(2)	If the Director has not issued a decision on an Application for Permit-to-Drill, Form 2, or an Oil and Gas Location Assessment, Form 2A, within seventy-five (75) days of a determination that such application is complete, the operator may request a hearing before the Commission on the permit application.  Such a hearing shall be expedited but will be held only after both the 20 days’ notice and the newspaper notice are given as required by Section 34-60-108, C.R.S. However, the hearing can be held after the newspaper notice if all of the entities listed under Rule 503.b waive the 20-day notice requirement. 
303.d.	Revisions to Form 2 or Form 2A.  Prior to approval of the Form 2 or Form 2A permit application, minor revisions or requested information may be provided by contacting the COGCC staff. After approval, any substantive changes shall be submitted for approval on a Form 2 or Form 2A. A Sundry Notice, Form 4, shall be submitted, along with supplemental information requested by the Director, when non-substantive revisions are made after approval, and no additional fee shall be imposed.
303.e.	Incomplete applications.  Applications for Permit-to-Drill, Form 2, or Oil and Gas Location Assessments, Form 2A, which are submitted without the required attachments, the proper signature, or the required information, shall be considered incomplete and shall not be reviewed or approved. The COGCC staff shall notify the applicant in not more than ten (10) days of its receipt of the application of such inadequacies, except that the Director shall notify the applicant of inadequacies within three (3) business days of its receipt where the proposed Oil and Gas Location is covered by an accepted Comprehensive Drilling Plan. The applicant shall then have thirty (30) days from the date that it was contacted to correct or provide requested information, otherwise the application shall be considered withdrawn and the fee shall not be refunded.
303.f.	Information requests after completeness determination.  Subsequent to deeming an Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, complete, the Director may request from the operator additional information needed to complete review of and make a decision on such an application.  Such an information request shall not affect an operator’s ability to request a hearing pursuant to Rule 303.e seventy-five (75) days from the date the Form 2 or Form 2A was originally determined to be complete pursuant to Rule 303.h. 
303.g.	Permit expiration. 
(1)	Applications for Permit-to-Drill, Form 2.  Approval of a Form 2 shall become null and void if drilling operations on the permitted well are not commenced within two (2) years after the date of approval.  The Director shall not approve extensions to applications for Permit-to-Drill, Form 2.
	(2)	Oil and Gas Location Assessments, Form 2A.  If construction operations are not commenced on an approved Oil and Gas Location within three (3) years after the date of approval, then the approval shall become null and void. The Director shall not approve extensions to Oil and Gas Location Assessments, Form 2A. 
303.h.	Permits in areas pending Commission hearing. The Director may withhold the issuance of any Permit-to-Drill, Form 2, for any well or proposed well that is located in an area for which an application has been filed, or which the Commission has sought, by its own motion, to establish drilling units, in which case the hearing thereon shall be held at the next meeting of the Commission at which time the matter can be legally heard.
303.i.	Special circumstances for permit issuance without notice or consultation.  The Director may issue a permit at any time in the event that an operator files a sworn statement and demonstrates therein to the Director's satisfaction that:
(1)	The operator had the right or obligation under the terms of an existing contract to drill a well; and the owner or operator has a leasehold estate or a right to acquire a leasehold estate under said contract which will be terminated unless the operator is permitted to immediately commence the drilling of said well; or
(2)	Due to exigent circumstances (including a recent change in geological interpretation), significant economic hardship to a drilling contractor will result or significant economic hardship to an operator in the form of drilling stand by charges will result.
In the event the Director issues a permit under this rule, the operator shall not be required to meet obligations to Surface Owners, local governmental designees, the Colorado Department of Public Health and Environment, or Colorado Parks and Wildlife under Rule 305 (except Rules 305.e.(4) and 305.e.(6), for which compliance will still be required) and 306. The Director shall report permits granted in such manner to the Commission at regularly scheduled monthly hearings.
303.j.	Special circumstances for withholding approval of Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A.
(1)	The Director may withhold approval of any Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, for any proposed well or Oil and Gas Location when, based on information supplied in a written complaint submitted by any party with standing under Rule 522.a.(1), other than a local governmental designee, or by staff analysis, the Director has reasonable cause to believe the proposed well or Oil and Gas Location is in material violation of the Commission's rules, regulations, orders or statutes, or otherwise presents an imminent threat to public health, safety and welfare, including the environment, or a material threat to wildlife resources.  Any such withholding of approval shall be limited to the minimum period of time necessary to investigate and dismiss the complaint, or to resolve the alleged violation or issue. If the complaint is dismissed or the matter resolved to the dissatisfaction of the complainant, such person may consult with the parties identified in Rule 503.b.(7).
(2)	In the event the Director withholds approval of any Application for Permit-To-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, under this Rule 303.j., an operator may ask the Commission to issue an emergency order rescinding the Director's decision.
303.k.	Suspending approved Permit-To-Drill, Form 2.  Prior to the spudding of the well, the Director shall suspend an approved Permit-to-Drill, Form 2, if the Director has reasonable cause to believe that information submitted on the Permit-to-Drill, Form 2 was materially incorrect.  Under the circumstances described in Rule 303.i.(1) or (2), an operator may ask the Commission to issue an emergency order rescinding the Director's decision.
303.l.	Reclassification of stratigraphic well.  If a test for productivity is made in a stratigraphic well, the well must be reclassified as a well drilled for oil or gas and is subject to all of the rules and regulations for well drilled for oil or gas, including filing of reports and mechanical logs.
303.m.	Provisions for avoiding mine sites.  Any person holding, or who has applied for, a permit issued or to be issued under §34-33-101 to 137, C.R.S., may at their election, notify the Director of such permit or application.  Such notice shall include the name, mailing address and facsimile number of such person and designate by legal description the life-of-mine area permitted, or applied for, with the Division of Reclamation, Mining, and Safety.  As soon as practicable after receiving such notice and designation, the Director shall inform the party designated therein each time that a Permit-to-Drill, Form 2, is filed with the Director which pertains to a well or wells located or to be located within said life-of-mine area as designated. The provisions of Rule 303.i.(1) and (2) will not be applicable to this rule.
305.	FORM 2 AND 2A APPLICATION PROCEDURES 
a.	Pre-application notifications.  For Oil and Gas Locations proposed within an Urban Mitigation Area or within the Buffer Zone Setback, an Operator shall provide a “Notice of Intent to Conduct Oil and Gas Operations” to the persons specified herein not less than thirty (30) days prior to submitting a Form 2A Oil and Gas Location Assessment to the Director.
(1)	Urban Mitigation Area Notice to Local Government.  For Oil and Gas Locations within an Urban Mitigation Area, an Operator shall notify the local government in writing that it intends to apply for an Oil and Gas Location Assessment.  Such notice shall be provided to the Local Governmental Designee in those jurisdictions that have designated an LGD, and to the planning department in jurisdictions that have no LGD.  The notice shall include a general description of the proposed Oil and Gas Facilities, the location of the proposed Oil and Gas Facilities, the anticipated date operations (by calendar quarter and year) will commence, and that an additional notice pursuant to Rule 305.c. will be sent by the Operator.  This notice shall serve as an invitation to the local government to engage in discussions with the Operator regarding proposed operations and timing, local government jurisdictional requirements, and opportunities to collaborate regarding site development.  A local government may waive its right to notice under this provision at any time by providing written notice to an Operator and the Director. 
(2)	Exception Zone and Buffer Zone Setback Notice to the Surface Owner and Building Unit Owners.  For Oil and Gas Locations proposed within the Exception Zone or Buffer Zone Setback, Operators shall notify the Surface Owner and the owners of all Building Units that a permit to conduct Oil and Gas Operations is being sought.  The Operator may rely on the county assessor tax records to identify the persons entitled to receive the Notice.  Notice shall include the following:
A.	The Operator’s contact information; 
B.	The location and a general description of the proposed Well or Oil and Gas Facilities;
C.	The anticipated date operations will commence (by calendar quarter and year); 
D.	The Local Governmental Designee’s (LGD) contact information; 
E.	Notice that the Building Unit owner may request a meeting to discuss the proposed operations by contacting the LGD or the Operator; and
F.	A “Notice of Comment Period” will be sent pursuant to Rule 305.c. when the public comment period commences.
305.b.	Posting Form 2A and Form 2. 
(1)	Form 2A.  Upon receipt of an Oil and Gas Location Assessment, Form 2A, the Director shall, as provided by Rule 303.e, determine if the application is complete and, if so, post such Form 2A on the Commission’s website. The Commission shall provide concurrent electronic notice of such posting to the relevant Local Governmental Designee and Colorado Parks and Wildlife (where consultation is triggered pursuant to Rule 306.c) and the Colorado Department of Public Health and Environment (where consultation is triggered pursuant to Rule 306.d).  The website posting shall clearly indicate:
A.	The date on which the Form 2A was posted; 
B.	The date by which public comments must be received to be considered; 
C.	The address(es) to which the public may direct comments; and
D.	Where the proposed Oil and Gas Location is covered by an accepted Comprehensive Drilling Plan, directions for review of the Plan. 
(2)	Form 2.  If an Application for Permit-to-Drill, Form 2, is concurrently filed with a Form 2A, that fact shall be noted in the posting provided herein.  If a Form 2 is subsequently filed, only a summary notice of such filing, indicating that a Form 2A covering the well has been previously accepted or approved, shall be posted, with concurrent notice to the Local Governmental Designee and, where consultation with one of those agencies is triggered, the Colorado Parks and Wildlife or Colorado Department of Public Health and Environment. 
305.c.	Completeness determination and comment period notifications.  Upon receipt of a completeness determination from the Director, an Operator shall notify the persons specified herein of their opportunity to meet with the Operator pursuant to Rule 306 and submit written comments about the proposed Oil and Gas Location to the Director, the LGD, and the Operator, and shall provide information about the Oil and Gas Location as follows: 
(1)	Oil and Gas Location Assessment Notice (“OGLA Notice”).  
A.	Parties to be noticed:
i.	Surface Owners;
ii.	Owners of all Building Units within the Exception Zone Setback; and 
iii.	Owners of surface property within five hundred (500) feet of the proposed Oil and Gas Location, for proposed Oil and Gas Locations not subject to Rule 318A or 318B.  
The operator may rely on the tax records of the assessor for the county in which the affected lands are located to identify the persons entitled to receive the OGLA Notice.  
B.	The OGLA Notice shall be delivered by hand; certified mail, return-receipt requested; electronic mail, return receipt requested; or by other delivery service with receipt confirmation unless an alternative method of notice is pre-approved by the Director. 
C.	The OGLA Notice shall include:
i.	The Form 2A itself (without attachments); 
ii.	A copy of the information required under Rule 303.b.(3).C, 303.b.(3).D, 303.b.(3).F, and 303.b(3).J.i.;
iii.	The COGCC’s information sheet on hydraulic fracturing treatments except where hydraulic fracturing treatments are not going to be applied to the well in question;
iv.	Instructions on how Building Unit owners can contact their Local Governmental Designee;
v.	An invitation to meet with the Operator before Oil and Gas Operations commence on the proposed Oil and Gas Location;  
vi.	An invitation to provide written comments to the LGD, the Operator and to the Director regarding the proposed Oil and Gas Operations, including comments regarding the mitigation measures or Best Management Practices to be used at the Oil and Gas Location.  
(2)	Buffer Zone Notice.  A “Notice of Comment Period” shall be provided by postcard to owners of Building Units within the Buffer Zone.  The operator may rely on the county assessor tax records to identify the persons entitled to receive the Buffer Zone Notice.  Notice shall include the following information:
A.	The Operator’s contact information; 
B.	The Local Governmental Designee’s contact information; 
C.	The COGCC’s website address and telephone number;
D.	The location of the proposed Oil and Gas Facilities and the anticipated date operations will commence (by month and year); 
E.	An invitation to meet with the Operator before Oil and Gas Operations commence on the proposed Oil and Gas Location;  
F.	An invitation to provide written comments to the LGD, the Operator and to the Director regarding the proposed Oil and Gas Operations, including comments regarding the mitigation measures or Best Management Practices to be used at the Oil and Gas Location.  
(3)	Appointment of agent.  The Surface Owner or Building Unit owner may appoint an agent, including its tenant, for purposes of subsequent notice and for consultation or meetings under Rule 306.  Such appointment shall be made in writing to the operator and must provide the agent’s name, address, and telephone number. 
(4)	Tenants.  With respect to notices given under this Rule 305, it shall be the responsibility of the notified Surface Owner or Building Unit owner to give notice of the proposed operation to the tenant farmer, lessee, or other party that may own or have an interest in any crops or surface improvements that could be affected by such proposed operation. 
(5)	Waiver.  Any of the notices required herein may be waived in writing by the Surface Owner, its agent, or the Local Governmental Designee, provided that a waiver by a Surface Owner or its agent shall not prevent the Surface Owner or any successor-in-interest to the Surface Owner from rescinding that waiver if such rescission is in accordance with applicable law.
305.d.	Comment period.  The Director shall not approve a Form 2A, or any associated Form 2, for a proposed Well or Production Facility for twenty (20) days from posting pursuant to Rule 305.b, and shall accept and immediately post on the Commission’s website any comments received from the public, the Local Governmental Designee, the Colorado Department of Public Health and Environment, or Colorado Parks and Wildlife regarding the proposed Oil and Gas Location.  
(1)	The Director shall extend the comment period to thirty (30) days upon the written request during the twenty (20) day comment period by the Local Governmental Designee, the Colorado Department of Public Health and Environment, Colorado Parks and Wildlife, the Surface Owner, or an owner of surface property who receives notice under Rule 305.c.(1)(A).iii.  
(2)	For Oil and Gas Locations proposed within an Urban Mitigation Area or within five hundred (500) feet of a Building Unit, the Director shall extend the comment period to not more than forty (40) days upon the written request of the Local Governmental Designee received within the original 20 day comment period.
The Director shall post notice of an extension granted under this provision on the COGCC website within twenty-four (24) hours of receipt of the extension request.
305.e.	Permit approval. Upon the conclusion of the comment period and, where applicable, consultation with the Local Governmental Designee, Colorado Parks and Wildlife or Colorado Department of Public Health and Environment pursuant to Rules 306.b, 306.c. or 306.d, respectively, the Director may attach technically feasible and economically practicable conditions of approval to the Form 2 or Form 2A as the Director deems necessary to implement the provisions of the Act or these rules pursuant to Commission staff analysis or to respond to legitimate public health, safety, or welfare concerns expressed during the comment period.  Provided, that an applicant under Rule 503 who claims that such a condition is not technically feasible, economically practicable, or necessary to implement the provisions of the Act or these rules, or to respond to legitimate public health, safety, or welfare concerns shall have the burden of proof on that issue before the Commission. 
(1)	Notice of decision.  Upon making a decision on an Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, the Director shall promptly provide notification of the decision and any conditions of approval to the operator and to any party with standing to request a hearing before the Commission pursuant to Rule 503.b, unless such a party has waived in writing its right to such notice and the Director has been provided a copy of such waiver. 
(2)	Suspension of approval.  If a party, Surface Owner or local government  requests a hearing before the Commission pursuant to Rule 503.b on an Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, then it shall notify the Director in writing within ten (10) days after the issuance of the decision, setting forth the basis for the objection.  Upon receipt of such an objection, the Director shall suspend the approval of the Form 2 or Form 2A and set the matter for an expedited adjudicatory hearing. Such a hearing shall be expedited but will only be held after both the 20 days’ notice and the newspaper notice are given as required by Section 34-60-108, C.R.S. However, the hearing can be held after the newspaper notice if all of the entities listed under Rule 503.b waive the 20-day notice requirement. If such an objection is not received, the permit shall issue as proposed by the Director. 
(3)	Appeal. If the approval of a Form 2 or Form 2A is not suspended as provided for herein, the issuance of the approved Form 2 or Form 2A by the Director shall be deemed a final decision of the Commission, subject to judicial appeal. 
305.f.	Statutory Notice to Surface Owners.  Not less than thirty (30) days in advance of commencement of operations with heavy equipment for the drilling of a well, operators shall provide the statutorily required notice to the well site Surface Owner(s) as described below and the Local Governmental Designee in whose jurisdiction the well is to be drilled.  Notice to the Surface Owner may be waived in writing by the Surface Owner.  
(1)	Surface Owner Notice is not required on federal- or Indian-owned surface lands.
(2)	Surface Owner Notice shall be delivered by hand; certified mail, return-receipt requested; or  by other delivery service with receipt confirmation.  Electronic mail may be used if the Surface Owner has approved such use in writing.
(3)	The Surface Owner Notice must provide:
A.	The operator’s name and contact information for the operator or its agent;
B.	A site diagram or plat of the proposed well location and any associated roads and production facilities;
C.	The date operations with heavy equipment are expected to commence;
D.	A copy of the COGCC Informational Brochure for Surface Owners;
E.	A postage-paid, return-addressed post card whereby the Surface Owner may request consultation pursuant to Rule 306; and, 
F.	A copy of the COGCC Onsite Inspection Policy (See Appendix or COGCC website), where the Oil and Gas Location is not subject to a Surface-Use Agreement.
(4)	Notice of subsequent well operations.  An Operator shall provide to the Surface Owner or agent at least seven (7) days advance notice of subsequent well operations with heavy equipment that will materially impact surface areas beyond the existing access road or well site, such as recompleting or re-stimulating the well.
(5)	Notice during irrigation season.  If a well is to be drilled on irrigated crop lands between March 1 and October 31, the operator shall contact the Surface Owner or agent at least fourteen (14) days prior to commencement of operations with heavy equipment to coordinate drilling operations to avoid unreasonable interference with irrigation plans and activities.
(6)	Final reclamation notice.  Not less than thirty (30) days before any final reclamation operations are to take place pursuant to Rule 1004, the operator shall notify the Surface Owner.  Final reclamation operations shall mean those reclamation operations to be undertaken when a well is to be plugged and abandoned or when production facilities are to be permanently removed. Such notice is required only where final reclamation operations commence more than thirty (30) days after the completion of a well.
305.g.	Location Signage.  The Operator shall, concurrent with the Surface Owner Notice, post a sign not less than two feet by two feet at the intersection of the lease road and the public road providing access to the well site, with the name of the proposed well, the legal location thereof, and the estimated date of commencement.  Such sign shall be maintained until completion operations at the well are concluded.
306.	CONSULTATION AND MEETING PROCEDURES.  Following the notifications provided for in Rule 305.c, an Operator shall comply with the following consultation and meeting procedures:
a.	Surface owners.  The Operator shall consult in good faith with the Surface Owner, or the Surface Owner’s appointed agent as provided for in Rule 305 in locating roads, production facilities, and well sites, or other oil and gas operations, and in preparation for reclamation and abandonment.  Such consultation shall occur at a time mutually agreed to by the parties prior to the commencement of operations with heavy equipment upon the lands of the Surface Owner.  The Surface Owner or appointed agent may comment on preferred locations for wells and associated production facilities, the preferred timing of oil and gas operations, and mitigation measures or Best Management Practices to be used during Oil and Gas Operations. 
(1)	Information provided by operator.  When consulting with the Surface Owner or appointed agent, the operator shall furnish a description or diagram of the proposed drilling location; dimensions of the drill site; topsoil management practices to be employed; and, if known, the location of associated production or injection facilities, pipelines, roads and any other areas to be used for oil and gas operations (if not previously furnished to such Surface Owner or if different from what was previously furnished).
(2)	Waiver. The Surface Owner or the Surface Owner’s appointed agent may waive, permanently or otherwise, their right to consult with the operator at any time.  Such waiver must be in writing, signed by the Surface Owner, and submitted to the operator.  
306.b.	Local governments. 
(1)	Local governments that have appointed a Local Governmental Designee and have indicated to the Director a desire for consultation shall be given an opportunity to consult with the Applicant and the Director on a Permit-to-Drill, Form 2, or an Oil and Gas Location Assessment, Form 2A, for the location of roads, Production Facilities and Well sites, and mitigation measures or Best Management Practices during the comment period under Rule 305.b..
(2)	Within fourteen (14) days of being notified of a Form 2A completeness determination pursuant to Rule 305.c, the Local Governmental Designee may notify the Commission and the Colorado Department of Public Health and Environment by electronic mail of its desire to have the Colorado Department of Public Health and Environment consult on a proposed Oil and Gas Location, based on concerns regarding public health, safety, welfare, or impacts to the environment. 
(3)	For proposed Oil and Gas Locations within Exception Zone Setback or Urban Mitigation Areas, the Operator shall attend an informational meeting with Building Unit owners within the Exception Zone Setback or Urban Mitigation Area if the LGD requests such a meeting.  Such informational meetings may be held on an individual basis, in small groups, or in larger community meetings and shall be held at a convenient place and time.  
306.c.	Colorado Parks and Wildlife. 
(1)	Consultation to occur. 
A.	Subject to the provisions of Rule 1202.d, Colorado Parks and Wildlife shall consult with the Commission, the Surface Owner, and the Operator on an Oil and Gas Location Assessment, Form 2A, where:
i.	Consultation is required pursuant to a provision in the 1200-Series of these rules; 
ii.	The operator seeks a variance from a provision in the 1200-Series of these rules; or
iii.	Colorado Parks and Wildlife requests consultation because the proposed Oil and Gas Location would be within areas of known occurrence or habitat of a federally threatened or endangered species, as shown on the Colorado Parks and Wildlife Species Activity Mapping (SAM) system. 
B.	The Commission shall consult with Colorado Parks and Wildlife when an operator requests a modification of an existing Commission order to increase well density or otherwise proposes to increase well density to more than one (1) well per forty (40) acres, or the Commission develops a basin-wide order involving wildlife or wildlife-related environmental concerns or protections.
C.	Notwithstanding the foregoing, the requirement to consult with Colorado Parks and Wildlife may be waived by Colorado Parks and Wildlife at any time. 
(2)	Procedure. 
A.	The operator shall provide: 
i.	A description of the oil and gas operation to be considered, including location; 
ii.	Any other relevant available information on the oil and gas operation, the affected wildlife resource, or the provision(s) of the 1200-Series Rules upon which the consultation is based; and
iii.	Proposed mitigation for the affected wildlife resource. 
B.	The Commission shall take into account the information submitted by the operator consistent with Rule 1202.c. 
C.	The operator, the Commission, the Surface Owner, and Colorado Parks and Wildlife shall have forty (40) days to conduct the consultation called for in this section. Such consultation shall begin concurrent with the start of the public comment period.  If no consultation occurs within such 40-day period, the requirement to consult shall be deemed waived, and the Director shall consider the operator’s application on the basis of the materials submitted by the operator. 
(3)	Result of consultation under Rule 306.c. 
A.	As a result of consultation called for in this subsection, Colorado Parks and Wildlife may make written recommendations to the Commission on conditions of approval necessary to minimize adverse impacts to wildlife resources.  Where applicable, Colorado Parks and Wildlife may also make written recommendations on whether a variance request should be granted, under what conditions, and the reasons for any such recommendations. 
B.	Agreed-upon conditions of approval.  Where the operator, the Director, Colorado Parks and Wildlife, and the Surface Owner agree to conditions of approval for Oil and Gas Locations as a result of consultation, these conditions of approval shall be incorporated into approvals of an Oil and Gas Location Assessment, Form 2A, or Application for Permit-to-Drill, Form 2, where applicable. 
C.	Permit-specific conditions.  Where the consultation called for in this subsection results in permit-specific conditions of approval to minimize adverse impacts to wildlife resources, the Director shall attach such permit-specific conditions only with the consent of the affected Surface Owner. 
D.	Standards for consultation and initial decision.  Following consultation and subject to subsection C above and Rule 1202.c, the Director shall decide whether to attach conditions of approval to a Form 2A or Form 2, where applicable. In making this decision, the Director shall apply the criteria of Rule 1202. 
E.	Notification of decision to consulting agency. Where consultation occurs under Rule 306.c, the Director shall provide to Colorado Parks and Wildlife the conditions of approval for the Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, on the same day that he or she announces a decision to approve the application. 
306.d.	Colorado Department of Public Health and Environment. 
(1)	Consultation to occur. 
A.	The Commission shall consult with the Colorado Department of Public Health and Environment on an Oil and Gas Location Assessment, Form 2A, where: 
i.	Within fourteen (14) days of notification pursuant to Rule 305, the Local Governmental Designee requests the participation of the Colorado Department of Public Health and Environment in the Commission’s consideration of an Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, based on concerns regarding public health, safety, welfare, or impacts to the environment; 
ii.	The operator seeks from the Director a variance from, or consultation is otherwise required or permitted under, a provision of one of the following rules intended for the protection of public health, safety, welfare, or the environment: 
aa.	Rule 317B. Public Water System Protection;
bb.	Rule 325. Underground Disposal of Water; 
cc.	Rule 603. Statewide Location Requirements for Oil and Gas Facilities, Drilling, and Well Servicing Operations;
dd.	Rule 604. Location Requirements for Oil and Gas Facilities, Drilling,  and Well Servicing Operations in Designated Setback Location; 
ee.	Rule 608. Coalbed Methane Wells; 
ff.	Rule 805. Odors and Dust;
gg.	900-Series E&P Waste Management; or
hh.	Rule 1002.f. Stormwater Management. 
All requests for variances from these rules must be made at the time an operator submits a Form 2A. 
B.	The Commission shall consult with the Colorado Department of Public Health and Environment when an operator requests a modification of an existing Commission order to increase well density or otherwise proposes to increase well density to more than one (1) well per forty (40) acres, or the Commission develops a basin-wide order that can reasonably be anticipated to have impacts on public health, welfare, safety, or environmental concerns or protections. 
C.	Notwithstanding the foregoing, the requirement to consult with the Colorado Department of Public Health and Environment may be waived by the Colorado Department of Public Health and Environment at any time. 
(2)	Procedure. 
A.	Where required, the Commission and the Colorado Department of Public Health and Environment shall have forty (40) days to conduct the consultation called for in this section. Such consultation shall begin concurrent with the start of the public comment period. If no consultation occurs within such 40-day period, the requirement to consult shall be waived, and the Director shall consider the operator’s application on the basis of the materials submitted by the operator. 
B.	The consultation called for in this section shall focus on identifying potential impacts to public health, safety, welfare, or the environment from activities associated with the proposed Oil and Gas Location, and development of conditions of approval or other measures to minimize adverse impacts. 
C.	Where consultation occurs pursuant to Rule 306.d.(1).A, it may include:
i.	Review of the permit application; 
ii.	Discussions with the local governmental designee to better understand local government’s concerns; 
iii.	Discussions with the Commission, operator, Surface Owner, or those potentially affected; and 
iv.	Review of public comments. 
D.	Where consultation occurs pursuant to Rule 306.d.(1).A.ii, the Colorado Department of Public Health and Environment shall have the opportunity to: 
i.	Review the permit application, the request for variance, and the basis for the request; and
ii.	Discuss the request with the operator, the Surface Owner, and the Commission. 
E.	Where consultation occurs pursuant to Rule 306.d.(1).B, the Colorado Department of Public Health and Environment shall have the opportunity to: 
i.	Review the well-density increase application or draft Commission order; and
ii.	Discuss the request with the operator or proponent, the Commission, and the local governmental designee. 
(3)	Result of consultation under Rule 306.d. 
A.	As a result of consultation called for in this subsection, the Colorado Department of Public Health and Environment may make written recommendations to the Commission on conditions of approval necessary to protect public health, safety, and welfare or the environment. Such recommendations may include, but are not limited to, monitoring requirements or best management practices. Where applicable, the Colorado Department of Public Health and Environment may also make written recommendations on whether a variance request should be granted, under what conditions, and the reasons for any such recommendations. 
B.	Agreed-upon conditions of approval. Where the operator, the Director, the Colorado Department of Public Health and Environment, and the Surface Owner agree to conditions of approval for Oil and Gas Locations as a result of consultation, these conditions of approval shall be incorporated into approvals of an Oil and Gas Location Assessment, Form 2A, or Applications for Permit-to-Drill, Form 2, where applicable. 
C.	Standards for consultation and Director decision.  Following consultation, the Director shall decide whether to attach conditions of approval recommended by the Colorado Department of Public Health and Environment to a Form 2A or Form 2, where applicable. This decision shall minimize significant adverse impacts to public health, safety, and welfare, including the environment, consistent with other statutory obligations. 
D.	Notification of decision to consulting agency.  Where consultation occurs under Rule 306.d, the Director shall provide to the Colorado Department of Public Health and Environment the conditions of approval for the Application for Permit-to-Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, on the same day that he or she announces a decision to approve the application. 
306.e.	Meetings with Building Unit Owners Within a Buffer Zone Setback. 
(1)	Meetings with Building Unit Owners.  An Operator shall be available to meet with Building Unit owners who received an OGLA Notice or a Buffer Zone Notice pursuant to Rule 305.c. and requested a meeting regarding the proposed Oil and Gas Location.  Operators shall also be available to meet with such Building Unit owners if requested to do so by the Local Governmental Designee and such meetings shall comply with Rule 306.b.(3).  Such informational meetings may be held on an individual basis, in small groups, or in larger community meetings.  
(2)	Information provided by operator.  When meeting with Building Unit owners or their appointed agent(s) pursuant to subsection (1), above, the Operator shall provide the following information:  the date construction is anticipated to begin; the anticipated duration of pad construction, drilling and completion activities; the types of equipment anticipated to be present on the Location; and the operator’s interim and final reclamation obligation.  In addition, the Operator shall present a description and diagram of the proposed Oil and Gas Location that includes the dimensions of the Location and the anticipated layout of production or injection facilities, pipelines, roads and any other areas to be used for oil and gas operations.  The Operator and Building Unit owners shall be encouraged to discuss potential concerns associated with Oil and Gas Operations, such as security, noise, light, odors, dust, and traffic, and shall provide information on proposed or recommended Best Management Practices or mitigation measures to eliminate, minimize or mitigate those issues. 
(3)	Waiver.  The Building Unit owner or agent may waive, permanently or otherwise, the foregoing meeting requirements.  Any such waiver shall be in writing, signed by the owner or agent, and shall be submitted by the Building Unit owner or agent to the operator and the Director.  
(4)	Mitigation Measures.  Operators will consider all legitimate concerns related to public health, safety, and welfare raised during informational meetings or in written comments and, in consultation with the Director and Local Governmental Designee if the LGD so requests, will add relevant and appropriate Best Management Practices or mitigation measures as Conditions of Approval into the Form 2A and any associated Form 2s.  
(5)	Operator Certification.  The Director shall not approve a Form 2A, Oil and Gas Location Assessment, until the operator certifies it has complied with the meeting requirements of this Rule 306.e.
f.	Final reclamation consultation.  In preparing for final reclamation and plugging and abandonment, the operator shall use its best efforts to consult in good faith with the affected Surface Owner (or the tenant when the Surface Owner has requested that such consultation be made with the tenant).  Such good faith consultation shall allow the Surface Owner (or appointed agent) the opportunity to provide comments concerning preference for timing of such operations and all aspects of final reclamation, including, but not limited to, the desired final land use and seed mix to be applied.
g.	Tenants.  Operators shall have no obligation to consult with tenant farmers, lessees, or any other party that may own or have an interest in any crops or surface improvements that could be affected by the proposed operation unless the Surface Owner appoints such person as its agent for such purposes.  Nothing shall prevent the Surface Owner from including a tenant in any consultation, whether or not appointed as the Surface Owner’s agent.

SERIES SAFETY REGULATIONS
602.	GENERAL
The training and action of employees, as well as proper location and operation of equipment is an important part of any safety program.  While this section is general in nature, it is considered a basic part of the foundation of any safety program.
a.	Employees shall be familiarized with these rules and regulations as provided herein as they relate to their function in their respective jobs.  Each new employee should have his job outlined, explained and demonstrated.
b.	Unsafe and potentially dangerous conditions as defined by these rules, should be reported immediately by employees to the supervisor in charge and shall be remedied as soon as practical.  Any accident involving injury to well site personnel or to a member of the general public which requires medical treatment or significant damage to equipment or the well site shall be reported to the Director as soon as practicable, but in no event later than twenty-four (24) hours after the accident.  A COGCC Accident Report, Form 22, shall be submitted to the Director within ten (10) days of the accident.  Accidents that require only first aid treatment are not subject to these reporting requirements. 
Where unsafe or potentially dangerous conditions exist, the owner or operator shall respond as directed by an agency with demonstrated authority to do so (such as sheriff, fire district director, etc.).
c.	Vehicles of persons not involved in drilling, production, servicing, or seismic operations shall be located a minimum distance of one hundred (100) feet from the wellbore, or a distance equal to the height of the derrick or mast, whichever is greater.   Equivalent safety measures shall be taken where terrain, location or other conditions do not permit this minimum distance requirement.
d.	Existing wells, not including previously plugged and abandoned wells, are exempt from the provisions of these regulations as they relate to the location of the well.
e.	Existing producing facilities shall be exempt from the provisions of these regulations with respect to minimum distance requirements and setbacks unless they are found by the Director to be unsafe.
f.	Self-contained sanitary facilities shall be provided during drilling operations and at any other similarly staffed oil and gas operations facility.

603.	STATEWIDE LOCATION REQUIREMENTS FOR OIL AND GAS FACILITIES, DRILLING, AND WELL SERVICING OPERATIONS
a.	Statewide location requirements. 
(1)	At the time of initial drilling, a Well shall be located not less than two hundred (200) feet from buildings, public roads, major above ground utility lines, or railroads.  Rule 604 setback requirements apply with respect to Building Units and Designated Outside Activity Areas. 
(2)	A well shall be located not less than one hundred fifty (150) feet from a surface property line.  The Director may grant an exception if it is not feasible for the Operator to meet this minimum distance requirement and a waiver is obtained from the offset Surface Owner(s).  An exception request letter stating the reasons for the exception shall be submitted to the Director and accompanied by a signed waiver(s) from the offset Surface Owner(s).  Such waiver shall be written and filed in the county clerk and recorder's office and with the Director.
603.b.	Statewide rig floor safety valve requirements.  When drilling or well servicing operations are in progress on a well where there is any indication the well will flow hydrocarbons, either through prior records or present conditions, there shall be on the rig floor a safety valve with connections suitable for use with each size and type of tool joint or coupling being used on the job.
603.c.	Statewide static charge requirements.  Rig substructure, derrick, or mast shall be designed and operated to prevent accumulation of static charge.
603.d.	Statewide well servicing pressure check requirements.  Prior to initiating well servicing operations, the well shall be checked for pressure and steps taken to remove pressure or operate safely under pressure before commencing operations.
603.e.	Statewide well control equipment and other safety requirements.  Well control equipment and other safety requirements are:
(1)	When there is any indication that a well will flow, either through prior records, present well conditions, or the planned well work, blowout prevention equipment shall be installed in accordance with Rule 317 or any special orders of the Commission.
(2)	Blowout prevention equipment when required by Rule 317 shall be in accordance with API RP 53: Recommended Practices for Blowout Prevention Equipment Systems, or amendments thereto.
(3)	While in service, blowout prevention equipment shall be inspected daily and a preventer operating test shall be performed on each round trip, but not more than once every twenty-four (24) hour period.  Notation of operating tests shall be made on the daily report.
(4)	All pipe fittings, valves and unions placed on or connected with blowout prevention equipment, well casing, casinghead, drill pipe, or tubing shall have a working pressure rating suitable for the maximum anticipated surface pressure and shall be in good working condition as per generally accepted industry standards.
(5)	Blowout prevention equipment shall contain pipe rams that enable closure on the pipe being used.  The choke line(s) and kill line(s) shall be anchored, tied or otherwise secured to prevent whipping resulting from pressure surges.
(6)	Pressure testing of the casing string and each component of the blowout prevention equipment, if blowout prevention equipment is required, shall be conducted prior to drilling out any string of casing except conductor pipe.  The minimum test pressure shall be five hundred (500) psi, and shall hold for fifteen (15) minutes without pressure loss in order for the casing string to be considered serviceable. Upon demand the operator shall provide to the Commission the pressure test evidence.  Drilling operations shall not proceed until blowout prevention equipment is tested and found to be serviceable.
(7)	If the blind rams are closed for any purpose except operational testing, the valves on the choke lines or relief lines below the blind rams should be opened prior to opening the rams to bleed off any pressure.
(8)	All rig employees shall have adequate understanding of and be able to operate the blowout prevention equipment system.  New employees shall be trained in the operation of blowout prevention systems as soon as practicable to do so.
(9)	Drilling contractors shall place a sign or marker at the point of intersection of the public road and rig access road.
(10)	The number of the public road to be used in accessing the rig along with all necessary emergency numbers shall be posted in a conspicuous place on the drilling rig.
603.f.	Statewide equipment, weeds, waste, and trash requirements.  All locations, including wells and surface production facilities, shall be kept free of the following: equipment, vehicles, and supplies not necessary for use on that lease; weeds; rubbish, and other waste material.  The burning or burial of such material on the premises shall be performed in accordance with applicable local, state, or federal solid waste disposal regulations and in accordance with the 900-Series Rules.  In addition, material may be burned or buried on the premises only with the prior written consent of the Surface Owner.
603.g.	Statewide equipment anchoring requirements. All equipment at drilling and production sites in geological hazard and floodplain areas shall be anchored to the extent necessary to resist flotation, collapse, lateral movement, or subsidence.
604.	SETBACK AND MITIGATION MEASURES FOR OIL AND GAS FACILITIES, DRILLING, AND WELL SERVICING OPERATIONS 
a.	Setbacks.  Effective August 1, 2013:
(1)	Exception Zone Setback.  No Well or Production Facility shall be located five hundred (500) feet or less from a Building Unit except as provided in Rules 604.a.(1) A and B, and 604.b. 
A.	Urban Mitigation Areas.  The Director shall not approve a Form 2A or associated Form 2 proposing to locate a Well or a Production Facility within an Exception Zone Setback in an Urban Mitigation Area unless:

i.	the Operator submits a waiver from each Building Unit Owner  within five hundred (500) feet of the proposed Oil and Gas Location with the Form 2A or associated Form 2, or obtains a variance pursuant to Rule 502; and

ii.	the Operator certifies it has complied with Rules 305.a, 305.c., and 306.e.; and

iii.	the Form 2A or Form 2 contains conditions of approval related to site specific mitigation measures sufficient to eliminate, minimize or mitigate potential adverse impacts to public health, safety, welfare, the environment, and wildlife to the maximum extent technically feasible and economically practicable; or

iv.	the Oil and Gas Location is approved as part of a Comprehensive Drilling Plan pursuant to Rule 216.
B.	Non-Urban Mitigation Area Locations.  Except as provided in subsection 604.b., below, the Director shall not approve a Form 2 or Form 2A proposing to locate a Well or a Production Facility within an Exception Zone Setback not in an Urban Mitigation Area unless the Operator certifies it has complied with Rules 305.a., 305.c., and 306.e., and the Form 2A or Form 2 contains conditions of approval related to site specific mitigation measures sufficient to eliminate, minimize or mitigate potential adverse impacts to public health, safety, welfare, the environment, and wildlife to the maximum extent technically feasible and economically practicable.
(2)	Buffer Zone Setback.  No Well or Production Facility shall be located one thousand (1,000) feet or less from a Building Unit until the Operator certifies it has complied with Rule 306.e. and the Form 2A or Form 2 contains conditions of approval related to site specific mitigation measures as necessary to eliminate, minimize or mitigate potential adverse impacts to public health, safety, welfare, the environment, and wildlife.
(3)	High Occupancy Buildings.  No Well or Production Facility shall be located one thousand (1,000) feet or less from a High Occupancy Building Unit without Commission approval following Application and Hearing.  Exception Zone Setback mitigation measures pursuant to Rule 604.c. shall be required for Oil and Gas Locations within one thousand (1,000) feet of a High Occupancy Building, unless the Commission determines otherwise.  
(4)	Designated Outside Activity Areas.  No Well or Production Facility shall be located three hundred fifty (350) feet or less from the boundary of a Designated Outside Activity.  The Commission, in its discretion, may establish a setback of greater than three hundred fifty (350) feet based on the totality of circumstances.  Buffer Zone Setback mitigation measures pursuant to Rule 604.c. shall be required for Oil and Gas Locations within one thousand (1,000) feet of a Designated Outside Activity Area, unless the Commission determines otherwise.  
(5)	Maximum Achievable Setback.  If the applicable setback would extend beyond the area on which the Operator has a legal right to locate the Well or Production Facilities, the Operator may seek a variance under Rule 502.b. to reduce the setback to the maximum achievable distance.  
604.b.	Exceptions.
(1)	Existing Oil and Gas Locations.  The Director may grant an exception to setback distance requirements set forth in rule 604 within a Designated Setback Location when a Well or Production Facility is proposed to be added to an existing or approved Oil and Gas Location if the Director determines alternative locations outside the applicable setback are technically or economically impracticable; mitigation measures imposed in the Form 2 or Form 2A will eliminate, minimize or mitigate noise, odors, light, dust, and similar nuisance conditions to the extent reasonably achievable; the proposed location complies with all other safety requirements of these Commission Rules; and:
A.	An existing or approved Oil and Gas Location is within a Designated Setback Location solely as a result of the adoption of Rule 604.a., above, which established the Designated Setback Locations; or
B.	The Oil and Gas Location is located within a Designated Setback Location solely as a result of Building Units constructed after the Oil and Gas Location was approved by the Director. 
(2)	Existing Surface Use Agreement or Site Specific Development Plan.  The Director shall grant an exception to setback requirements set forth in rule 604.a. for a Surface Use Agreement or site specific development plan (as defined in § 24-68-102(4)(a), C.R.S. that establishes vested property rights as defined in § 24-68-103, C.R.S.), that was executed on or before August 1, 2013, and which expressly governs the location of Wells or Production Facilities on the surface estate, provided mitigation measures imposed in the Form 2 or Form 2A will eliminate, minimize or mitigate noise, odors, light, dust, and similar nuisance conditions to the extent reasonably achievable and the location complies with all other safety requirements of these Commission Rules. 
(3)	Surface Development after August 1, 2013 Pursuant to a Surface Use Agreement or Site Specific Development Plan.  A Surface Owner or Building Unit owner and mineral owner or mineral lessee may agree to locate future Building Units closer to existing or proposed Oil and Gas Locations than otherwise allowed under Rule 604.a. pursuant to a valid Surface Use Agreement or site specific development plan (as defined in § 24-68-102(4)(a), C.R.S., that establishes vested property rights as defined in § 24-68-103, C.R.S.) that expressly governs the location of Wells or Production Facilities on the surface estate.  All setback, notice, consultation and meeting requirements contained in Rules 305, 306, and 604.a shall apply with respect to all Building Units that are not governed by the applicable SUA or site specific development plan. Copies of any applicable SUA or site specific development plan shall be submitted by the Operator with a Form 2A Application or associated Form 2 for a proposed Oil and Gas Location on the relevant surface estate.
(4)	In the event the Director refuses to grant an exception or variance requested pursuant to Rule 604.a.(5) or 604.b., a hearing before the Commission shall be held at the next regularly scheduled meeting of the Commission, subject to the notice requirements of Rule 507. 
604.c.	Mitigation Measures.  The following requirements apply to an Oil and Gas Location within a Designated Setback Location and such requirements shall be incorporated into the Form 2A or associated Form 2 as Conditions of Approval.  
(1)	Provisions for future encroaching development.  If a location comes within a Designated Setback Location solely as a result of surface development after well pad construction begins or production equipment has been placed, certain mitigation measures may not apply as determined by the Director. 
(2)	Location Specific Requirements – Designated Setback Locations.  Subject to Rule 502.b., the following mitigation measures shall apply to any Well or Production Facility proposed to be located within a Designated Setback Location for which a Form 2 Application for Permit to Drill or Form 2A Oil and Gas Location Assessment is submitted on or after August 1, 2013: 
A.	Noise.  Operations involving pipeline or gas facility installation or maintenance, or the use of a drilling rig, are subject to the maximum permissible noise levels for Light Industrial Zones, as measured at the nearest Building Unit.  Short-term increases shall be allowable as described in 802.c.  Stimulation or re-stimulation operations and Production Facilities are governed by Rule 802. 
B.	Closed Loop Drilling Systems – Pit Restrictions. 
i.	Closed loop drilling systems are required within the Buffer Zone Setback.
ii.	Pits are not allowed on Oil and Gas Locations within the Buffer Zone  Setback, except fresh water storage pits, reserve pits to drill surface casing, and emergency pits as defined in the 100-Series Rules.
iii.	Fresh water pits within the Exception Zone shall require prior approval of a Form 15 pit permit.  In the Buffer Zone, fresh water pits shall be reported within 30-days of pit construction.
iv.	Fresh water storage pits within the Buffer Zone Setback shall be conspicuously posted with signage identifying the pit name, the operator’s name and contact information, and stating that no fluids other than fresh water are permitted in the pit.  Produced water, recycled E&P waste, or flowback fluids are not allowed in fresh water storage pits. 
v.	Fresh water storage pits within the Buffer Zone Setback shall include emergency escape provisions for inadvertent human access. 
C.	Green Completions – Emission Control Systems.
i.	Flow lines, separators, and sand traps capable of supporting green completions as described in Rule 805 shall be installed at any Oil and Gas Location at which commercial quantities of gas are reasonably expected to be produced based on existing adjacent wells within 1 mile.
ii.	Uncontrolled venting shall be prohibited in an Urban Mitigation Area.
iii.	Temporary flowback flaring and oxidizing equipment shall include the following:
aa.	Adequately sized equipment to handle 1.5 times the largest flowback volume of gas experienced in a ten (10) mile radius;
bb.	Valves and porting available to divert gas to temporary equipment or to permanent flaring and oxidizing equipment; and
cc.	Auxiliary fuel with sufficient supply and heat to sustain combustion or oxidation of the gas mixture when the mixture includes non-combustible gases.
D.	Traffic Plan.  If required by the local government, a traffic plan shall be coordinated with the local jurisdiction prior to commencement of move in and rig up.  Any subsequent modification to the traffic plan must be coordinated with the local jurisdiction.
E.	Multiwell Pads.
i.	Where technologically feasible and economically practicable, operators shall consolidate wells to create multi-well pads, including shared locations with other operators.  Multi-well production facilities shall be located as far as possible from Building Units.
ii.	The pad shall be constructed in such a manner that noise mitigation may be installed and removed without disturbing the site or landscaping.
iii.	Pads shall have all weather access roads to allow for operator and emergency response.
F.	Leak Detection Plan.  The Operator shall develop a plan to monitor Production Facilities on a regular schedule to identify fluid leaks.
G.	Berm construction.  Berms or other secondary containment devices in Designated Setback Locations shall be constructed around crude oil, condensate, and produced water storage tanks and shall enclose an area sufficient to contain and provide secondary containment for one-hundred fifty percent (150%) of the largest single tank.  Berms or other secondary containment devices shall be sufficiently impervious to contain any spilled or released material.  All berms and containment devices shall be inspected at regular intervals and maintained in good condition. No potential ignition sources shall be installed inside the secondary containment area unless the containment area encloses a fired vessel.  Refer to American Petroleum Institute Recommended Practices, API RP - D16.
H.	Blowout preventer equipment (“BOPE”).  Blowout prevention equipment for drilling operations in a Designated Setback Location shall consist of (at a minimum):
i.	Rig with Kelly.  Double ram with blind ram and pipe ram; annular preventer or a rotating head.
ii.	Rig without Kelly.  Double ram with blind ram and pipe ram.
Mineral Management certification or Director approved training for blowout prevention shall be required for at least one (1) person at the well site during drilling operations.
I.	BOPE testing for drilling operations.  Upon initial rig-up and at least once every thirty (30) days during drilling operations thereafter, pressure testing of the casing string and each component of the blowout prevention equipment including flange connections shall be performed to seventy percent (70%) of working pressure or seventy percent (70%) of the internal yield of casing, whichever is less.  Pressure testing shall be conducted and the documented results shall be retained by the operator for inspection by the Director for a period of one (1) year.  Activation of the pipe rams for function testing shall be conducted on a daily basis when practicable.
J.	BOPE for well servicing operations.  
i.	Adequate blowout prevention equipment shall be used on all well servicing operations.
ii.	Backup stabbing valves shall be required on well servicing operations during reverse circulation.  Valves shall be pressure tested before each well servicing operation using both low-pressure air and high-pressure fluid.
K.	Pit level indicators.  Pit level indicators shall be used.
L.	Drill stem tests.  Closed chamber drill stem tests shall be allowed.  All other drill stem tests shall require approval by the Director.
M.	Fencing requirements.  Unless otherwise requested by the Surface Owner, well sites constructed within Designated Setback Locations, shall be adequately fenced to restrict access by unauthorized persons.
N.	Control of fire hazards.  Any material not in use that might constitute a fire hazard shall be removed a minimum of twenty-five (25) feet from the wellhead, tanks and separator.  Any electrical equipment installations inside the bermed area shall comply with API RP 500 classifications and comply with the current national electrical code as adopted by the State of Colorado.
O.	Loadlines.  All loadlines shall be bullplugged or capped.
P.	Removal of surface trash.  All surface trash, debris, scrap or discarded material connected with the operations of the property shall be removed from the premises or disposed of in a legal manner.
Q.	Guy line anchors.  All guy line anchors left buried for future use shall be identified by a marker of bright color not less than four (4) feet in height and not greater than one (1) foot east of the guy line anchor.
R.	Tank specifications.  All newly installed or replaced crude oil and condensate storage tanks shall be designed, constructed, and maintained in accordance with National Fire Protection Association (NFPA) Code 30 (2008 version).  The operator shall maintain written records verifying proper design, construction, and maintenance, and shall make these records available for inspection by the Director.  Only the 2008 version of NFPA Code 30 applies to this rule.  This rule does not include later amendments to, or editions of, the NFPA Code 30. NFPA Code 30 may be examined at any state publication depository library.  Upon request, the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203, will provide information about the publisher and the citation to the material.
S.	Access roads.  At the time of construction, all leasehold roads shall be constructed to accommodate local emergency vehicle access requirements, and shall be maintained in a reasonable condition.
T.	Well site cleared.  Within ninety (90) days after a well is plugged and abandoned, the well site shall be cleared of all non-essential equipment, trash, and debris. For good cause shown, an extension of time may be granted by the Director.
U.	Identification of plugged and abandoned wells.  The operator shall identify the location of the wellbore with a permanent monument as specified in Rule 319.a.(5).  The operator shall also inscribe or imbed the well number and date of plugging upon the permanent monument.
V.	Development from existing well pads.  Where possible, operators shall provide for the development of multiple reservoirs by drilling on existing pads or by multiple completions or commingling in existing wellbores (see Rule 322).  If any operator asserts it is not possible to comply with, or requests relief from, this requirement, the matter shall be set for hearing by the Commission and relief granted as appropriate.
W.	Site-specific measures.  During Rule 306 consultation, the operator may develop a mitigation plan to address location specific considerations not otherwise addressed by specific mitigation measures identified in this subsection 604.c.
(3)	Location Specific Requirements – Exception Zone Setback.  Within the Exception Zone Setback, the following mitigation measures will be mandatory:
A.	All mitigation measures required pursuant to subsection 604.c.(2), above, and:
B.	Berm Construction:
i.	Containment berms shall be constructed of steel rings, designed and installed to prevent leakage and resist degradation from erosion or routine operation. 
ii.	 Secondary containment areas for tanks shall be constructed with a synthetic or engineered liner that contains all primary containment vessels and flowlines and is mechanically connected to the steel ring to prevent leakage.  
iii.	For locations within five hundred (500) feet and upgradient of a surface water body, tertiary containment, such as an earthen berm, is required around Production Facilities.
iv.	In an Urban Mitigation Area Exception Zone Setback, no more than two (2) crude oil or condensate storage tanks shall be located within a single berm.  
605.	OIL AND GAS FACILITIES.
a.	Crude Oil and Condensate Tanks.
(1)	Atmospheric tanks used for crude oil storage shall be built in accordance with the following standards as applicable.  Only those editions of standards cited within this rule shall apply to this rule; later amendments do not apply.  The material cited in this rule is available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203.  In addition, these materials may be examined at any state publication depository library.
A.	Underwriters Laboratories, Inc., No. UL-142, “Standard for Steel above ground Tanks for Flammable and Combustible Liquids,” 9th Edition (December 28, 2006);
B.	American Petroleum Institute Standard No. 650, “Welded Steel Tanks for Oil Storage,” 11th Edition (June 2007); 
C.	American Petroleum Institute Standard No. 12B, “Bolted Tanks for Storage of Production Liquids,” 15th Edition (October 2008, effective March 31, 2009); 
D.	American Petroleum Institute Standard No. 12D, “Field Welded Tanks for Storage of Production Liquids,” 11th Edition (October 2008, effective March 31, 2009); or
E.	American Petroleum Institute Standard No. 12F, “Shop Welded Tanks for Storage of Production Liquids,” 12th Edition (October 2008, effective March 31, 2009).
(2)	Tanks shall be located at least two (2) diameters or three hundred fifty (350) feet, whichever is smaller, from the boundary of the property on which it is built.  Where the property line is a public way the tanks shall be two thirds (2/3) of the diameter from the nearest side of the public way or easement.
A.	Tanks less than three thousand (3,000) barrels capacity shall be located at least three (3) feet apart.
B.	Tanks three thousand (3,000) or more barrels capacity shall be located at least one-sixth (1/6) the sum of the diameters apart. When the diameter of one tank is less than one-half (1/2) the diameter of the adjacent tank, the tanks shall be located at least one-half (1/2) the diameter of the smaller tank apart.
(3)	At the time of installation, tanks shall be a minimum of two hundred (200) feet from any building unit.
(4)	Berms or other secondary containment devices shall be constructed around crude oil, condensate, and produced water tanks to provide secondary containment for the largest single tank and sufficient freeboard to contain precipitation.  A synthetic or engineered liner shall be placed directly beneath each above-ground tank.  Berms and secondary containment devices and all containment areas shall be sufficiently impervious to contain any spilled or released material.  Berms and secondary containment devices shall be inspected at regular intervals and maintained in good condition.  No potential ignition sources shall be installed inside the secondary containment area unless the containment area encloses a fired vessel.  Any electrical equipment installations inside the bermed area shall comply with API RP 500 classifications and comply with the current national electrical code as adopted by the State of Colorado.
(5)	Tanks shall be a minimum of seventy-five (75) feet from a fired vessel or heater-treater.
(6)	Tanks shall be a minimum of fifty (50) feet from a separator, well test unit, or other non-fired equipment.
(7)	Tanks shall be a minimum of seventy-five (75) feet from a compressor with a rating of 200 horsepower, or more.
(8)	Tanks shall be a minimum of seventy-five (75) feet from a wellhead.
(9)	Gauge hatches on atmospheric tanks used for crude oil storage shall be closed at all times when not in use.
(10)	Vent lines from individual tanks shall be joined and ultimate discharge shall be directed away from the loading racks and fired vessels in accord with API RP 12R-1, 5th Edition (August 1997, reaffirmed April 2, 2008). Only the 5th Edition of the API standard applies to this rule; later amendments do not apply. The API standard is available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. In addition, these materials may be examined at any state publication depository library. 
(11)	During hot oil treatments on tanks containing thirty-five (35) degree or higher API gravity oil, hot oil units shall be located a minimum of one hundred (100) feet from any tank being serviced.
(12)	Labeling of tanks.  All tanks and containers shall be labeled in accordance with Rule 210.d.  
605.b.	Fired Vessel, Heater-Treater.
(1)	Fired vessels (FV) including heater-treaters (HT) shall be minimum of fifty (50) feet from separators or well test units.
(2)	FV-HT shall be a minimum of fifty (50) feet from a lease automatic custody transfer unit (LACT).
(3)	FV-HT shall be a minimum of forty (40) feet from a pump.
(4)	FV-HT shall be a minimum of seventy-five (75) feet from a well.
(5)	At the time of installation, fired vessels and heater treaters shall be a minimum of two hundred (200) feet from residences, building units, or well defined normally occupied outside areas.
(6)	Vents on pressure safety devices shall terminate in a manner so as not to endanger the public or adjoining facilities.  They shall be designed so as to be clear and free of debris and water at all times.
(7)	All stacks, vents, or other openings shall be equipped with screens or other appropriate equipment to prevent entry by wildlife, including migratory birds. 
605.c.	Special Equipment.  Under unusual circumstances special equipment may be required to protect public safety. The Director shall determine if such equipment should be employed to protect public safety and if so, require the operator to employ same. If the operator or the affected party does not concur with the action taken, the Director shall bring the matter before the Commission at public hearing.
(1)	All wells located within five hundred (500) feet of a Residenial Building Unit or well defined normally occupied outside area(s), shall be equipped with an automatic control valve that will shut the well in when a sudden change of pressure, either a rise or drop, occurs. Automatic control valves shall be designed so they fail safe.
(2)	Pressure control valves required in (a) shall be activated by a secondary gas source supply, and shall be inspected at least every three (3) months to assure they are in good working order and the secondary gas supply has volume and pressure sufficient to activate the control valve.
(3)	All pumps, pits, and producing facilities shall be adequately fenced to prevent access by unauthorized persons when the producing site or equipment is easily accessible to the public and poses a physical or health hazard.
(4)	Sign(s) shall be posted at the boundary of the producing site where access exists, identifying the operator, lease name, location, and listing a phone number, including area code, where the operator may be reached at all times unless emergency numbers have been furnished to the county commission or its designee.
605.d.	Mechanical Conditions. All valves, pipes and fittings shall be securely fastened, inspected at regular intervals, and maintained in good mechanical condition.
605.e.	Buried or partially buried tanks, vessels, or structures.  Buried or partially buried tanks, vessels, or structures used for storage of E&P waste shall be properly designed, constructed, installed, and operated in a manner to contain materials safely.  A synthetic or engineered liner shall be placed directly beneath. Such vessels shall be tested for leaks after installation and maintained, repaired, or replaced to prevent spills or releases of E&P waste.
605.f.	Produced water pits, special use and buried or partially buried vessels, or structures. At the time of initial construction, pits shall be located not less than  five hundred (500) feet from any building unit. 

AESTHETIC AND NOISE CONTROL REGULATIONS
802.	NOISE ABATEMENT
a.	The goal of this rule is to identify noise sources related to oil and gas operations that impact surrounding landowners and to implement cost-effective and technically-feasible mitigation measures to bring oil and gas facilities into compliance with the allowable noise levels identified in subsection c.  Operators should be aware that noise control is most effectively addressed at the siting and design phase, especially with respect to centralized compression and other downstream “gas facilities” (see definition in the 100 Series of these rules).
802.b.	Oil and gas operations at any well site, production facility, or gas facility shall comply with the following maximum permissible noise levels.  

ZONE	7:00 am to next 7:00 pm	7:00 pm to next 7:00 am	
Residential/Agricultural/Rural 	55 dB (A)	50 dB (A)	
Commercial	60 dB (A)	55 dB (A)	
Light industrial	70 dB (A)	65 dB (A)	
Industrial	80 dB (A)	75 dB (A)	
The type of land use of the surrounding area shall be determined by the Director in consultation with the Local Governmental Designee taking into consideration any applicable zoning or other local land use designation.  In the hours between 7:00 a.m. and the next 7:00 p.m. the noise levels permitted above may be increased ten (10) dB(A) for a period not to exceed fifteen (15) minutes in any one (1) hour period.  The allowable noise level for periodic, impulsive or shrill noises is reduced by five (5) dB (A) from the levels shown.
(1)	Except as required pursuant to Rule 604.c.(2)A., operations involving pipeline or gas facility installation or maintenance, the use of a drilling rig, completion rig, workover rig, or stimulation is subject to the maximum permissible noise levels for industrial zones.  
(2)	In remote locations, where there is no reasonably proximate Building Unit or Designated Outside Activity Area, the light industrial standard may be applicable.
(3)	Pursuant to Commission inspection or upon receiving a complaint from a nearby property owner or Local Governmental Designee regarding noise related to oil and gas operations, the Commission shall conduct an onsite investigation and take sound measurements as prescribed herein.
802.c.	The following provide guidance for the measurement of sound levels and assignment of points of compliance for oil and gas operations:
(1)	Sound levels shall be measured at a distance of three hundred and fifty (350) feet from the noise source.  At the request of the complainant, the sound level shall also be measured at a point beyond three hundred fifty (350) feet that the complainant believes is more representative of the noise impact.  If an oil and gas well site, production facility, or gas facility is installed closer than three hundred fifty (350) feet from an existing occupied structure, sound levels shall be measured at a point twenty-five (25) feet from the structure towards the noise source.  Noise levels from oil and gas facilities located on surface property owned, leased, or otherwise controlled by the operator shall be measured at three hundred and fifty (350) feet or at the property line, whichever is greater.
In situations where measurement of noise levels at three hundred and fifty (350) feet is impractical or unrepresentative due to topography, the measurement may be taken at a lesser distance and extrapolated to a 350-foot equivalent using the following formula:
dB (A) DISTANCE 2  = dB (A) DISTANCE 1  – 20 x  log 10 (distance 2/distance 1)
(2)	Sound level meters shall be equipped with wind screens, and readings shall be taken when the wind velocity at the time and place of measurement is not more than five (5) miles per hour.
(3)	Sound level measurements shall be taken four (4) feet above ground level.
(4)	Sound levels shall be determined by averaging minute-by-minute measurements made over a minimum fifteen (15) minute sample duration if practicable. The sample shall be taken under conditions that are representative of the noise experienced by the complainant (e.g., at night, morning, evening, or during special weather conditions).
(5)	In all sound level measurements, the existing ambient noise level from all other sources in the encompassing environment at the time and place of such sound level measurement shall be considered to determine the contribution to the sound level by the oil and gas operation(s).
802.d.	In situations where the complaint or Commission onsite inspection indicates that low frequency noise is a component of the problem, the Commission shall obtain a sound level measurement twenty-five (25) feet from the exterior wall of the residence or occupied structure nearest to the noise source, using a noise meter calibrated to the dB (C) scale. If this reading exceeds 65 dB (C), the Commission shall require the operator to obtain a low frequency noise impact analysis by a qualified sound expert, including identification of any reasonable control measures available to mitigate such low frequency noise impact.  Such study shall be provided to the Commission for consideration and possible action.
802.e.	Exhaust from all engines, motors, coolers and other mechanized equipment shall be vented in a direction away from all building units.
802.f.	All Oil and Gas Facilities with engines or motors which are not electrically operated that are within four hundred (400) feet of Building Units shall be equipped with quiet design mufflers or equivalent.  All mufflers shall be properly installed and maintained in proper working order.
803.	LIGHTING
To the extent practicable, site lighting shall be directed downward and inward and shielded so as to avoid glare on public roads and building units within one thousand (1000) feet.
804.	VISUAL IMPACT MITIGATION
Production facilities, regardless of construction date, that can be seen from any public highway shall be painted with uniform, non-contrasting, non-reflective color tones (similar to the Munsell Soil Color Coding System), and with colors matched to but slightly darker than the surrounding landscape.
805.	ODORS AND DUST
805.a.	General.  Oil and gas facilities and equipment shall be operated in such a manner that odors and dust do not constitute a nuisance or hazard to public welfare.
805.b.	Odors.
(1)	Compliance. 
A.	Oil and gas operations shall be in compliance with the Department of Public Health and Environment, Air Quality Control Commission, Regulation No. 2 Odor Emission, 5 C.C.R. 1001-4, Regulation No. 3 (5 C.C.R. 1001-5), and Regulation No. 7 Section XVII.B.1 (a-c) and Section XII. 
B.	No violation of Rule 805.b.(1) shall be cited by the Commission, provided that the practices identified in Rule 805.b.(2) are used. 
(2)	Production Equipment and Operations.
A.	Crude Oil, Condensate, and Produced Water Tanks.  All crude oil, condensate, and produced water tanks with uncontrolled actual emissions of volatile organic compounds (VOC) of five (5) tons per year (tpy) or greater, located within 1,320 feet of a Building Unit, or a Designated Outside Activity Area shall use an emission control device capable of achieving 95% control efficiency of VOC and shall obtain a  permit as required by Colorado Department of Public Health and Environment, Air Pollution Control Commission Regulation as set forth in 805. b. (1). 
B.	Glycol Dehydrators.  All glycol dehydrators with uncontrolled actual emissions of VOC of five (5) tpy or greater, located within 1,320 feet of a Building Unit , or a Designated Outside Activity Area shall use an emission control device capable of achieving 90% control efficiency of VOC and shall obtain a  permit as required by Colorado Department of Public Health and Environment, Air Pollution Control Commission Regulation as set forth in 805.b.(1).
C.	Pits.  Pits with uncontrolled actual emissions of VOC of five (5) tpy or greater shall not be located within 1,320 feet of a Building Unit, or a Designated Outside Activity Area.  For the purposes of this section, compliance with Rule 902.c is required.  Operators may provide site-specific data and analyses to COGCC staff establishing that pits potentially subject to this subsection do not have a potential to emit VOC of five (5) tpy or greater. 
D.	Pneumatic Devices.  Low- or no-bleed pneumatic devices must be used when existing pneumatic devices are replaced or repaired, and when new pneumatic devices are installed.
(3)	Well completions. 
A.	Green completion practices are required on oil and gas wells where reservoir pressure, formation productivity, and wellbore conditions are likely to enable the well to be capable of naturally flowing hydrocarbon gas in flammable or greater concentrations at a stabilized rate in excess of five hundred (500) MCFD to the surface against an induced surface backpressure of five hundred (500) psig or sales line pressure, whichever is greater.  Green completion practices are not required for exploratory wells, where the wells are not sufficiently proximate to sales lines, or where green completion practices are otherwise not technically and economically feasible. 
B.	Green completion practices shall include, but not be limited to, the following emission reduction measures:
i.	The operator shall employ sand traps, surge vessels, separators, and tanks as soon as practicable during flowback and cleanout operations to safely maximize resource recovery and minimize releases to the environment. 
ii.	Well effluent during flowback and cleanout operations prior to encountering hydrocarbon gas of salable quality or significant volumes of condensate may be directed to tanks or pits (where permitted) such that oil or condensate volumes shall not be allowed to accumulate in excess of twenty (20) barrels and must be removed within twenty-four (24) hours. The gaseous phase of non-flammable effluent may be directed to a flare pit or vented from tanks for safety purposes until flammable gas is encountered. 
iii.	Well effluent containing more than ten (10) barrels per day of condensate or within two (2) hours after first encountering hydrocarbon gas of salable quality shall be directed to a combination of sand traps, separators, surge vessels, and tanks or other equipment as needed to ensure safe separation of sand, hydrocarbon liquids, water, and gas and to ensure salable products are efficiently recovered for sale or conserved and that non-salable products are disposed of in a safe and environmentally responsible manner. 
iv.	If it is safe and technically feasible, closed-top tanks shall utilize backpressure systems that exert a minimum of four (4) ounces of backpressure and a maximum that does not exceed the pressure rating of the tank to facilitate gathering and combustion of tank vapors. Vent/backpressure values, the combustor, lines to the combustor, and knock-outs shall be sized and maintained so as to safely accommodate any surges the system may encounter. 
v.	All salable quality gas shall be directed to the sales line as soon as practicable or shut in and conserved.  Temporary flaring or venting shall be permitted as a safety measure during upset conditions and in accordance with all other applicable laws, rules, and regulations. 
C.	An operator may request a variance from the Director if it believes that using green completion practices is infeasible due to well or field conditions, or would endanger the safety of wellsite personnel or the public.
D.	 In instances where green completion practices are not technically feasible, operators shall employ Best Management Practices (BMPs) to reduce emissions.  Such BMPs shall consider safety and shall include measures or actions to minimize the time period during which gases are emitted directly to the atmosphere, and monitoring and recording the volume and time period of such emissions. 
805.c.	Fugitive dust. Operators shall employ practices for control of fugitive dust caused by their operations.  Such practices shall include but are not limited to the use of speed restrictions, regular road maintenance, restriction of construction activity during high-wind days, and silica dust controls when handling sand used in hydraulic fracturing operations. Additional management practices such as road surfacing, wind breaks and barriers, or automation of wells to reduce truck traffic may also be required if technologically feasible and economically reasonable to minimize fugitive dust emissions.