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Home My WebLink About20130054.tiffRESOLUTION RE: EXPRESSION OF OPPOSITION TO NEW SETBACK AND NOTIFICATION RULES UNDER CONSIDERATION BY THE COLORADO OIL AND GAS CONSERVATION COMMISSION WHEREAS, the Board of County Commissioners of Weld County, Colorado, pursuant to Colorado statute and the Weld County Home Rule Charter, is vested with the authority of administering the affairs of Weld County, Colorado, and WHEREAS, the Colorado Oil and Gas Conservation Commission ("COGCC") is considering the adoption of amendments to current rules and new rules governing setbacks for oil and gas wells and production facilities, and notification of adjacent property owners on whose properties residential buildings are located, and WHEREAS, a draft of the proposed amendments and new rules were provided to parties to the rulemaking on December 31, 2012 ("the 12-31-12 Draft Setback and Notification Rules"), and WHEREAS, the 12-31-12 Draft Setback and Notification Rules would require all oil and gas wells and production facilities to be located at least 500 feet away from residential buildings ("the exception zone"), unless, for "non -urban mitigation zone locations," the Operator certifies it has complied with Rule 306.e., and the Form 2A or Form 2 contains "conditions of approval 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 pursuant to Rule 604.c.;" and for "urban mitigation zone locations," the Operator 1) submits a waiver from each person owning a building unit or building permitted for construction 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; 2) certifies it has complied with Rule 306.e. and all applicable safety requirements of the rules and regulation; and 3) the Operator's Form 2A or Form 2 contains "conditions of approval 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 pursuant to Rule 604.c." and WHEREAS, the 12-31-12 Draft Setback and Notification Rules would require Operators who wish to locate oil and gas wells or production facilities within a "buffer zone" of 1,000 feet of any residential building to certify that it has "complied with Rule 306.e. and the Form 2A or Form 2 contains conditions of approval pursuant to Rule 604.c as necessary to eliminate, minimize or mitigate potential adverse impacts to public health, safety, welfare, the environment, and wildlife," and -36TV\ --. �L� �C ICDS( 354 k-77-13 201 3 BC0044 RE: EXPRESSION OF OPPOSITION TO NEW SETBACK AND NOTIFICATION RULES UNDER CONSIDERATION BY THE COLORADO OIL AND GAS CONSERVATION COMMISSION PAGE 2 WHEREAS, the 12-31-12 Draft Setback and Notification Rules would require Operators who wish to locate oil and gas wells or production facilities within either the exception zone or the buffer zone to provide notice to the owners of the residential buildings, detailing certain required information, and WHEREAS, after the rulemaking proceedings on December 11, 2012, Weld County staff reviewed Assessor maps of properties located in the Greater Wattenburg Area (GWA) to better understand current setbacks from occupied buildings. Staff found that although wellheads are routinely located within center -pivot irrigation circles, production facilities (including tank batteries) are placed in corners of fields to avoid the circles. At those locations, the production facilities typically are 500 to 1,000 feet away from occupied buildings. This review is consistent with the information presented in the table on page 25 of the Colorado oil and Gas Conservation Commission (COGCC) Staff Report, dated November 15, 2012. That table shows that 11.6% of the well spots in Weld County reviewed in the years 2009 to 2012 (through November 6, 2012) were within "exception zones," and 32.7% were within "buffer zones." The production facilities appear to be even further away from residential buildings, and WHEREAS, Weld County's "local governmental designee" staff (Bruce T. Barker, Weld County Attorney, and David Bauer, Director, Weld County Public Works Department) have recorded few calls with complaints regarding setbacks and the issues covered in the 12-31-12 Draft Setback and Notification Rules since 2006, and WHEREAS, the information presented in the above "Whereas" paragraphs show that in Weld County, and particularly in the GWA, the 12-31-12 Draft Setback and Notification Rules are not necessary, and WHEREAS, the 12-31-12 Draft Setback and Notification Rules' requirement of notice to residential building owners within the exception and buffer zones, coupled with the required determinations by COGCC staff as to whether or not the Operator's Form 2A or Form 2 contains "conditions of approval 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 pursuant to Rule 604.c.," for "exception zones," and whether the Operator has properly certified that it has "complied with Rule 306.e. and the Form 2A or Form 2 contains conditions of approval pursuant to Rule 604.c as necessary to eliminate, minimize or mitigate potential adverse impacts to public health, safety, welfare, the environment, and wildlife," gives owners of residential buildings improper standing to object to oil and gas operations on adjacent properties, without any such authorization by the Colorado General Assembly, and 2013-0054 BC0044 RE: EXPRESSION OF OPPOSITION TO NEW SETBACK AND NOTIFICATION RULES UNDER CONSIDERATION BY THE COLORADO OIL AND GAS CONSERVATION COMMISSION PAGE 3 WHEREAS, for the reasons stated above, the Board of County Commissioners opposes the 12-31-12 Draft Setback and Notification Rules. NOW, THEREFORE, BE IT RESOLVED by the Board of County Commissioners of Weld County, Colorado, that the Board opposes for the 12-31-12 Draft Setback and Notification Rules, for above -stated reasons. The above and foregoing Resolution was, on motion duly made and seconded, adopted by the following vote on the 2nd day of January, A.D., 2013. BOARDUNTY COMMISSIONERS WELD /SOU$TY COLORADO ATTEST: bad Weld County Clerk to the Boar o-Tem BY: D uty Clerk APPROVED AS TO FORM: ounty Attorney arba Kirkmeyer Date of signature: 1(31)0 2013-0054 BC0044 1.)H Al. I I )cccmbcr "31. 2012 (STAKEHOLDER DRAFT REVISION 1) DEFINITIONS (l00 Series) Application for Development shall have the meaning set forth in C R S § 24$5 5-102(2)(e). puffer Zone Location. Any art:wrong Oil and Gas Location with a wellhead or production facility located one thousand (1 0001 feet or less from a Residential Building Unit shall constitute a Buffer Zone Location. The moaas %ement for otdetemxnino the Buffer Zgpp shall he made from the wellhead or Produtllon Facility nearest any Building Unit to the nearest wall or corner of such Building Unit. Designated Qµt(u,)onP locations shall mean any Oil and Gas I ovation within, or proecateL L110 constructed within a Buffer Zone Location Exception 20ne I °cation within one thousand 11.000) feet of a High Occupancy Building Unit. shall be any Ed 1. Nursing Name, Beerdaed Gene Facility. or Jailyin eh 's J xejw-W1oserve or within three hundred fifty (50i -or more persons 350), feet W.&Designated Outside Activity Area -shag -mean-, Designated OutsldtActivlty Area: Upon Application and ljeafirg the Commission. in its discretion may establish a OesignatedQuiside Activity Area (DOAA) for (a] An outdoor venue; euelees-aplayglound,_of recreation area, euldeer-iheolefaueh as a pyavarrol nd permanent roods field amphitheate( or other 'miler ace of public assembly - Owned Q operated by a local pov,,t tent which the local povemment seeks albat&p egtfi4tished as a Designated Outside Asti dry la f (Mb) all ovidei r venue or recreation area, such as a playground permanent spoils field amphitheater g other similar place of public assembly whore Ingress to, or egress from the venue could be impeded in the event of an emergency condition at an Oil and Gas Location located tens than three hundred and fifty (350) feet from the venue duo to the configuration of the venue and the number of persons known or expected to a Staneerwusgrpy Inc venue en .regular basis -Upr n Ap(rs:, ea anG Hrarirg, the Commiseem-sbaiLdetenttme-based eMhetelality of cirewneto ..,cc. t-h•-Mor an outdoor venue conslituteree-Deskjeated-Outetde Aril AN Am, and, if so. the pehimsiw noire )ary4f-ute0esgnaled O pontosasof Rule 60..c - -antra woe* occupy the venue on a regular basis The Commission shall determine whether le establish a Designated Outside Activity Area and if so. the aporoofiate_boundaries for the DOHA based on the totality of circumstances_and cnnshslent with the putpoffi ct the Oil and Gas Conservation Acl fxceotlon Zone Location. Anv prrgosed Oil and Gas Location with g Well or Production Facility located five hundred (5Q0) feel or less fran a Residential Building Unit shall constitute an Exception Zone Location. The cement for of deteeninino he E ceotlon Zane shall be made from the eltead or production Fatality_m!ilras( any Buitdino Unit to the nearest wall or comer of such Building UMt. filph Occupancy Budding Unit shall mean: (a) any operating Public School as defined in C RS 6 22-7- 703141' Nonpublic School as Q5f10ed in CRS 622-305-103% 5) Nurs'na Facility as definan C.RS 425 54.103114)' Hospital; Lilo care Inst414i0ns as defined in C.R.S. § 12-13401.. or Correctional Facility as debnod I0 C R S 617-1-102(1.7). proviGQQ. the facility or institution roouladv serves fifty (50) or more oemona' or (b) an operabe Child Care Center as defined in C R. S. 6 26S102(1 5) 2013-0054 Rtsidontlal Building Unit shag mean ho be defined( %dace Owner shall mean the owner of the surface estate upon which a Well, Produdi0n FacWty OII and Gas Location or OII and Gas Facility is located or oronosed to be located pursuant to a Finn 2 or Form 2A. kp-¢ApeVhl➢.Agresment shall mean a vaad contract between an Operator and a Surface Owner, or their respective predecessors in interest that 9QfOfj)LJfl whole or in part Oil and Gas Operations on the surface estate. Urban Mitigation Zone shall mean any area ingr(USf ,(ALatieyi twenty•two (221 Building Units or one (1) High Occupancy Building Unit exist or are under construction within a 72 -plow citclg born' ps radius 1 0QQ feet measured from any wellhead or Production Facility to the nearest wall or Ginn@rof_erw,Buffc*ng Unit or fel at least eleven f 111 Building Units or one HI High Occupancy Building Unit exist or are under construction within a 36 acre semicircle of the sane radius. An Urban Mitigation Zone shall be determined at the time a Form 2A or Fenn 2 is submitted 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 parson shall filo with the Director an application on Form 2, Application for Permit -to -Drill, Deepen. Re-enter or Recomplete and Operate (Application for Permitto-Drd), 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. aL(2)--Operational Conflict. The Permit to Drill shall be binding with respect to env operationally conflicting local governmental permit or land use approval orooess (a).31 FIIIng Fees. A Form 2, Appeo Lion for Permit -to -Drill, shall be submitted with a fiing and service ree established by the Commission (see Appendix III >. Wells dnlled for stratigraphic information only shall be exempt from paying the filing and service fee. (3)(41 (3) A request to deepen. re-enter. rocomplete to a different reservoir. or to dnll a sidetrack of an existing well shall be filed on a Form 2. Application for Perma-to.Dnll. including details of the proposed work and a wellbore diagram. (4lf51 (4)—A Form 2, Application to Permit -to -Drill, shale specify the distance between the wall or corner of the nearest Building Unit and the proposed wellhead. Compliance with Rules 3C6e: end 604-i lec V Miih.f-1000Wet-ofa8uilding Unit (6){13,)_(61—)pfotmatlon Reoulrements, Attached to and part of the Form 2, Application for Permit -to -Drill, as filed shall be a current OW by 11" scaled drawing of the entire sections) 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. R--Uwloxwonanddeecriptwe name of all buildings within 350 feet of the proposed welt - 303.6 FORM 2A, OIL AND GAS LOCATION ASSESSMENT. (1) Unless exempted under subsection 2. belowa 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 end 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 wall or a pit extent an Emergency Pit or a Flare Pit vMere there is no risk of condensate acarmulatiot 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 dnhing a new well or constructing a odor purposes described In subsections 303 b ( 11 B and C. above a an existing Oil and Gas Location within the onglnaly disturbed wee. even 4 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 Dating 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 whore 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 comer of the nearest Building Unit and the proposed or existing wellhead or Production Facility closest to said Building Unit.-GernplargewNh Rules 306. e: and 604 is required if any wellhead or onjproductioe4asds -ie-loll W;rWWa70004eeputORwlding 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 or major equipment components to be used In conjunction with drllhng and operating the well(s), including all tanks. pits. flares. combustion equipment. separators, and other ancillary equipment and a description of any pipelines for PI, gas or water. D. A sealed drawing. or sealed aenal photograph shoving the approximate outline of the Qd._aad_as_Losahon and the well or reference point use for measuring d. tanc95..IlxLdrd'mna shrill incgt all visible improvements within five hundred (500) feet of the proposed Oil and Gas Location, with a horizontal distance and approximate bearing Iran Oil and Gas Location. Visible improvements shall include, but not be limited to, all buildings or residences, publicly maintained roads and trails. major above -ground utility lines. railroads, pipelines. mines. oil wells, gas wells injection wells, water wells known to the operator and those registered with the Colorado State Engineer, known springs plugged wells, know 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 O4 and Gas Location, If any. shall be attached to the scaled drawng. II there are no visible Improvements within five hundred (500) feet of a proposed Oil and Gas location. it shall be so noted on the roan 2A. E. A topographic map showing all surface waters and ripadan areas within one thousand (1,000) feel of the proposed Oil and Gas Location, with a horizontal distance and approximate beanng from the Oil and Gas Location. F. An 8 1,2" by I I' 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 uses) and basis for setting reclamation standards. i. M 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. n. 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: as. 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 lime up to hvelve (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 lande with a slope ten percent (10%) or greater, or one (1) foot of elevation gain or more in ten (10) fcol distance, then the following shall be required: i. Construction layout drawing (construction and operation); and II. Location cross section plot (construction and operation). J. H the proposed Oil end Gas Location is within 4000one thousand (1.0001 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 n. A Waste Management Plan maeungdesrsibing how the Operator intends to satisfy the general requirements cf Rule 907.a. K. If the orcoosed Oil and Gas Location is within an Urban Mitigaltnjonn rw%wnre than the local government received the Local Government Advance Notice feou{fed by Rule 305 d (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. I.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 thee relevant Surface Use Agreement. MN. If the proposed Oa and Gas Location is covered by a Comprehensive Drilling Plan accepted pursuant to Rule 216, a list of any conditions of approval. NO.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 Oa and Gas Location. OP. Designation of whether the proposed Oil and Gas Location is within sensitive wildlife habitat or a restricted surface occupancy area. PQ.IC the proposed Oil and Gas Location is within a zone defined in Rule 3176, Table 1. documentation that the applicant has provided notification of the application submittal to potentially impacted public water Systems within fifteen (IS) stream miles downstream. OR.Any additional data as reasonably required by the Commission as a result of consultation with the Colorado Department of Public Health and Eiwlronnen% or Colorado Parks and Wildlife. R. 01 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.CA. §1342 and 1344 of the Water Pollution and Control Act (Section 404 of the federal "Clean Water Act) for construction ot an Oct and Gas Location the operator shall so indicate on the Oil and Gas Location Assessment, Form 2/L 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. 303.1. 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. 303.1. 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 534-33-101 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 won 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 We -of -mine area as designated. The provisions of Rule 303.t(1) and (2) will not be applicable to this rule. 305 NOTICEFORN 2 AND 2A PO$TINfe COMMENT, APPROVAL AND NOTIFICATION icons -or Rule 305 a regarding surfaceowners-shall-Pol-appiy-te4edefal-ef Indian awned stufeee ao4s b•-Peeting. 11) Form Us Posting Form 2A and Form 2. (71 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 appkcation is complete and, if so, peat 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 Hearth and Environment (where consultation is triggered pursuant to Rule 306.d) The website posting shall dearly 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-0rin, Form 2, is concurrently filed with a Form 2A. that fact shell be noted in the posting provided herein. If a Form 2 is subsequently filed, oily a summary notice of such tiling. 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 e.305 b. Comment period. (s4-€xceptren Zone. The Director shall not approve a Form 2A. or any associated Form 2. for a proposed we0heedIAC or Production Facility-valhin--ari--6soeplion-Zone for forty (4GAwenty 120) days from posting pursuant to Rule 305.✓}--anel-sball-assept and immenately-sesfron-the-COnl misaigrl a website any comme4s-reseived-itern-the-p.blic the Leea4-Governmental-Ooygnes, Me Colorado Deportment of Pubac Nalth and Environment o olote e-Talks-:ski-4Wldide-regarding the proposed -Oil w -d Ges I.nraeon The Din -2A after menty (20)-daye-if-tira-cif-she determinesall Building Unit owners within -the &sapt:ov Etc S;wo 443F-w<wotl Ines rghl to consent -0144in subiection 305.e (I) above,-the-Oueeter-rap-net horn ', for twenty (20) days from porai ng-puesnent-to Rule 306-b, and shall accept and immediately poet on the Commission's website any comments received Iran the pubes, the Local Governmental Designee. the Colorado Department of Public Health and Environment. or Colorado Parks and Wildlife regarding the proposed Oil and Gas Location. Lf,)_The Director shad extend the comment period to thirty (30) days upon the written request during the twenty (20) day comment period by the Local Govemmental 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.e. The -Direder-+;lralFyosNhe-oxteseen-o1 ho COGGG-vr..be14-wtllur-twenty four (24) hours of receipt-ef the one -e'en rosr9 d- I2LEoE Sll _arid Gas Locations orc used within an Exception Zone or Buffer Zone. the Director shallCXLIId the comment period to not more than forty (40) days upon the wiaen request of Ibtiocal Governmental Designee received within the original 20 day comment period, The Director shag post notice of an extension wanted under this provision on the CQGQ.Q webslte within twentv4our (24) hours of receint of the extension reouest. 305.c. Conditions of approval; issuance of permit Upon the conclusion of the comment penod and. where applicable, consultation with the Local Governmental Designee. Colorado Petits and Wildlife or Colorado Department of Public Health and Environment pursuant to Rules 300.b 30)5,c. or 305.d, respectively, the Director may attach technically feasible and economically practicable conditions of approval to the Fong 2 or Fond 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 pu tigJlealtltaeldty or welfare concems expressed during the comment period. Provided, that an applicant under Rule 503 who clams 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 end Gas Location Assessment, Form 2A the Director shall promptly provide notification of the decision and any c0nd410ns of approval to the operator and to any party with standing to lquest a heaving before the Commission pursuant to Rule 503.b. unless such a party has waived in willing Its right to such notice and the Director has been provided a copy of such waiver (2) Suspension of approval. If a party with standing to do so requests a hearing before the Commission pursuant to Rule 503.b on an Application for Permn-to-Doll, 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 tor en expedited adjudicatory hearing. Such a hearing shall be expedited but will only be held after both the 20 days' notice end the newspaper notice are given as required by Section 34.00.108, C. R S. However, the hearing can be held after the newspaper notice if all of the entities listed under Rule 503.b waive the 20 - day notice requirement If such an objection is not received, the permit shall issue as proposed by the Director (3) Appeal. If the approval of a Form 2 or Form 2A is not suspended as provided for herein, the Issuance of the approved Form 2 or Form 2A by the Director shall be deemed a final decision of the Commission, subject to judicial appeal. e. -305.d. Notice D_)_(I) Local Government Advance Notice. Fuel Oil and Gas I *cations within the Urban Midoaeon Zone an Operator shall notify the local Government in wahine that it intends to sooty for an Oil and Gas Location Assessment not less than thirty (301 days odor to submitting a Form 2A to the Director. Such Advance Renee Shall be Provided to the Local Governmental Designee in those iuAsdictions that have design toot allot LGC and to the Manton° department in jurisdictions that have no LGD. Such Advance Notice OW Include a General dwedotion of the proposed Oil and Gas Facilities, the location of the pSpposod Od anfLCae Facilities and the anticipated date operations will commence. This Advance_Nogce shall serve as an invltarion to the I octal Govemm,mlal Deeionee to en_ in discussions with the Operate redardnq-proposed onempons and timMa. and to notify the Operator of oppodueities for ecitakcgatten w1t111pC.'y ryoverrmeOI aoenries or other Operators, and ot local aoverrrnent tunsdl¢irl!1aLr athzC91Cnis A local govermten nosy waive as rieht to notice under this provision at any limo by orovai0g mitten notice to an Operator and the Director. (4)(2)_Surface Owner Notice. 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 Ownerts) 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 vatting by the Surface Owner. A. Surface Owner Notice Is rat stulfed on federal- or Indian -owned surface lands Sudace Owner Notice shall be delivered by hand or by; certified mail, return - receipt requested,' or by other deliven service with receipt confimation. ,ppecbonj&.melLrlay be used if the Surface Owner has eooroved such use in writino. B,ci—The Surface Owner Notice must provide: i. The operator's name and contact Information for the operator or its agent: ii. A site diagram or plat of the proposed well location and any associated roads and production facilities; in. The data operations with heavy equpment are expected to commence; N. A copy of the COGCC Informational Brochure for Surface Owners: v. A postage -paid. return -addressed post card whereby the Surface Owner may request consultation pursuant to Rule 306; and, vi. A copy of the COGCC OnMe Inspection Policy (See Appendix or COGCC website). where the Oil and Gas Location is not subject to a surface -use agreement (24)Oil and Gas Location Assessment Notice ("OGLA Notice")1 Upon receipt of a completeness determination from the Director, the Applicant for an Oil and Gas Location Assessment, Form 2A, shall prompt), provide the information described below to the fdlowing parties; A. Parties to be netted: 1 Owners of an Building Units within the Exception Buffer Zone:so4 ii. Owners of surface property within INe hundred (500) feet of the proposed Oil and Gas Location. for proposed Oil and Gas Locations not subject to Rule 318A or 3188. 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-er-by, certified mail, return -receipt requested to owners of surface property or Building- [oae:: gr by other delrvery service with receipt confirmation unless an alternative method of notice is pre -approved by the Director. C. The OGLA Notice shall include: The Form 2A itself (without attachments); ii. A copy of the inloimation required under Rule 303.b.(3).C, 303.b.{3).D, 303.b.(3).F, and 303.b(3).JJ.; 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:ar e iv trep-attetienal-lirteanabori)nstmdtions on how Building Unit owners can IabS t their Lgcel cNeinmental Designee: iy—An invitation to meet with the Operator deems epproprata v. The-OGLA Notice shag-mfurn-44w-ereptonl-thal-the-Template application (M dudeg.ahachmenla) may-be-revieweaan-the-COGGO websitebefore Oil and gtat,he or she may submitoemmentIne-efrefevidedOn the GOGO6wao .--Gag Operations commence on the proposeditacd Cqe 1 oration vi. (3An invitation to provide written comments to the L GP the Operator and to the Director regardino the or000sed Oil and Gas Operations. including comments regarding the mitigation measures or Best Management Practices Lo be used at the Oil and Gas Location ) Buffer Zone Notice. Notice shall be provided by postcard to owners of Building Units within the Buffer Zone. Netree-shat' onriude-operator oonteet tion about the proposedChiaha Cu -Operations. the date, time end-localiea-et-iNecmabenal meetings regarding I elation that-8uileing-tine-ev.ne a -may attend; that the comp4ote-Foon-aaneeplicationNavaitable on the COGC. v.e4eiia-ead that -Building Unit owners -may-subrM-eepwleatt to the Director as provided -on -the COCCC w baffle. The operator may roty on the county assesea tax records to identity the persons entitled to receive the Buffer Zone Notts. fg(Sg tbgll Include the fdlowiro information: A_f4The Operators contact INomaaon B. The Loral GovernmentalOeRJgQpe's contact information' C. The CO9CCt&webslle address and telephone number, and Gas_FaelNles and the anticipated date operation,' will commence C _ An invitation 10 meet with the Operator Ware Oil and Gas Operations commence on the orocosed Oil and Gas LOcabgB; F An invitation to provide written comments to the LGO. the Operator. 210 to the Director re taudlrp the ororogexl Oil and Gas Operations. (02tiding Comments reoardinp the mitigation measures or Best Management Practices10 be used at the Oil and Gas Locatitm, (5) Appointment of agent. The Surfacer or Building Unit owner may appoint an agent, including its tenant, for purposes of subsequent notice and for consultation pijedlnnc under Rule 306. Such appointment shall be made in writing to the operator and must provide the agent's name, address, and telephone number. (*Tenants. With respect to notices given under this Rule 305, it shall be the responsibility of the notified Surface Cromer or Building Unit owner to give notice of the proposed operation to the tenant fanner. 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 (GD Notice of subsequent well operations. An Operator shall provide to the Surface Owner or agent at least seven (7) days advance notice of subsequent well operations with heavy equipment that will materially impact surface areas beyond the existing access road or well site. such as recompletion or ref racturing of the well (r$) 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. (es) Final reclamation notice. Not less then thirty (30) days before any final reclamation operations we 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 aro to be permanently removed Such notice is required only where final reclamation operations commence more than thirty (30) days alter the completion of a well (4)1Q) Wester. 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. t- 305.e. Location Signage. The Operator shall, concurrent with the Surface Owner Notice, post a sign not less than two feet by two feet al 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 -CONSULTATION AND MEETING PROCEDURES. An Operator shall meet or fAlMtdtwiith the following persons: a. Surface owners. The Operator shall consult In good faith with a—Suwfaceewnero- the Surface Owner or the Surface Owners appointed mien( 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—tae-ape:-xor-Nrah-eoneoU-w.-gocd-fedh-with-the scatass-canterer-foe-suit .rer-s-epeek,c agent—as-prawded for in Rule 306._ Such consultation shall occur ate 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 of aooaitded aoem may comment on preferred locations for wells aid associatcd_Droduclion cookies the preferred amino of oil and on operations an4Jpjtlgatoi) measures or Best Management Practices to be used during O? and Gas.,0pel'ahofle (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 drib site: topsoil management practices to be employed: and, if known, the locatlen of associated production or injection facilities. pipelines, roads and any other areas to to used for oil and gas operations (if not previously furnished to such Solace Owner or if different horn what was previously furnished). I2) Good fahh consultation- The surface-. nw.o:annonno t get may calM „ - I :adustwn-rac.Fliee and on the preferred wrung of w endgaeope alwna: (3) (2LWelver. The Surface Owner or the Surface Owners appointed agent may waive their right to consult with the operator at any tine. Such waiver must be in writing stoned by the Surface Owner and submitted to the operator. Q&b Localgovemments. (1) Local governments that have appanted a Local Govemmental Designee and have indicated to the Director a desire for consultation shall be given an opportunity to consult with the Applicant end the Director on a Permit -to -DM, Form 2, or an Oil and Gas Location Assessment, Form 2k for the location of roads. Production Facilities and Wee sites poor le-the-Gelialle0640{r01-eperntioe -w -h. E mpreeni- local iudedlctionsl issues. Winding land uee .autdl.mWgapcaineasures or Best Meng meet Practices during the 121IBBleallenitiUndef.RUica0.S.b.. (2) Within fourteen (14) days of its-notuicatanbeina notified ors Form 2A completeness determination pursuant to Rule 305.e, 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 (,1 For moored Exception Zone or Urban hisioation Zone Oil and Gas I ocations the LGD may feouest that the operator hold informational meetinos for Building Unit owners within Waite Buffer Zones- Such informational meetings may be held on an lndivtdual basis to small drotps. or in larger, communityrn etirgg, I�a0 gpetator chooses to hold commurity meelinos, at least two meetings shall be held at limes that allow persona who have reoutss work schedules (between 9 tffi am and 600 o m 1 to attend a Lau (gcafion convenient to attendees ,1.Q¢,c. Colorado Parks and Wildlife. (t) Consultation to occur. A. Subject to the provisions of Rule 12024 Colorado Parks and Wildlife shall consult with the Commission, the Surface Owner, and Otte 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; li. The operator seeks a variance from a provision in the 1200 -series of these rules; or Ili 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 Parka 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 Wildtfe 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 penod 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: 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 Buffer Zone; 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 il. 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 Envirorrnent 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 end Gas Locations as a result of consultation, these conditions of approval shall be incorporated into approvals of an Oa and. Gas Location Assessment. Form 2A. or Applications for Pernik -to - Drill, Form 2, vmere applicable. C. Standards for consultation and Director decision. Following consultation. the Director shall decide whether to attach condlions of approval recommended by the Colorado Department of Public Health and Environment to a Form 2A or Form 2, where applicable. Ths decision shall minimize significant adverse impacts to public health, safely. 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. Sae Meetings with Building Unit Owners. (11 Exception Zone. For Oil and Gas Operat.onsLocationa proposed within them Exception Zone. as defined-in--RWe4O4,at43—are-the_operata shall meet and confer with 8uildng UM Owners who received the OGLA Notice puasugn(; Rule 3OS,e.f21 Such conferences may b0_lyxltLon an individual basis, in small groups. or therr—appointed--agents -regarding the pre esed-C aad-Gasiawabcrar Eao lies and -shall -in lamer canmunity_megAlffis._11s10 operator chooses to hold coft. ul ty meetings at least two meelinos shall be held at times that allow persons eta h;»re - 'War work schedules (between 8:00 a.m. and 6:00 p.m. yg attend and at a location convenient to attendees The Operator shall discuss the subjects identified in subsection 13). below. Operators shaDmnsider and address legitimate public hgalth safety and welfare concerns identified by the Building Unit owners through design and imrsesteentafton of Best Manaoemeni Practices or mitigation measures in consultation with the Director (2) Buffer Zone. For-C14Loa). us defined in Rule 604.a.(2). the operator shaftraid-infermakonei-neuA.ys-rer-andeing-Unit-irmrere Of their appointed agents within the Buffer ZoneAn Operator shall be available to meet ydgl Stadjag Unit owners who received a Buffer Zgne_Nolice pufsuanitoRute. 305 e (31 and who request q meeting regarding the proposed Oil and Gas l gnaiion or Facelifts Doerators 'hall also be available to meet with Bu:d'ng Unit owners d reauosied to do y{gj}y}he,j ocal Govemmenlal Designee. Such informational meetings may be held on an individual basis, in small gtoups, or in larger community meetings. If an operator chooses to hold community meetings. at least two meetings shall be held at times that allow persons who have regular wok schedules (between 8:00 am and 6:00 p.m ) to attend and at a location convenient to attendees. Th4 identified in subsection 3 below. (3) Infomsatfon provided by operator. When cenfeniag-er-meeting with Budding Unit owners or their appointed agent—or—tenant(s) pursuant to subsections (1) and (2), above, the Operator shall provide the following information no sooner than 90 days prior to drilling and not later than 30 days prior to dtbtitg: the date construction 6 anbapated 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 Operators 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 isseesroncems associated with Oil and Gas Operations. such as wordy noise, light. odors, dust, and traffic, and shall provide information on proposed_or ualnmmendt d Best Mate omen Practices or mitigation measures to eliminate. minimize or mitigate those issues (4) Waiver. The Building Unit owner or agent may waive the foregoing meeting requirements. Any such waiver shall be in veiling; signed by the owner or agent. and shall be submitted by the Building UM owner or agent to the operator. —If vs-likaglinst-idrid-subjest-te-sensulialian-le teaanFeasupled,-the-waiver shall be ratified s-^" ..'5qw44- if tenants change: seneiltalieeefaiteeramenicernent ofoperationt 45)--Mlegatlon Measures. Any getiorarcrw cs tropn'eci by et agreed is by the Operator shall be nciuded on the font. -2-'t t:om:-d4{5) Mitigation Measures. Operators will consider all legitimate concerns related to public health safgty, and welfare raised during informational t11ee(jpgs or in written comments andin consultation with the Director and Local Povernmental Designee if the LGD so requests. will add relevant and appropriate Best MarlEMMent Practices or mitigation measures as Qggdilignts of aooroval Into the Form 2A and any associated Form 2s. (6) Operator Certification. The Director shall not approve a Fan 2A, Oil and Gas Location Assessment. until the —operator certifies it taus+ requiremem,eithpr; A. The opcgatel oSlttfies it has eomolied with the meeting reguiromeJltg oU01S Rule 306 e' or 8 As a condition nf anoroval on a Fo 2A the Director reouges the Operator to hold the required informational meetings by the timefremes identified in subSection 306 e.f3L above oral lhoro$er to submit a Sundry Nobs Form 4, coibMna compliance with this Rule 306.e. and includme env resultant mitiealien measures or Best 6tanaoement Practices. f, Final reclamation consultation. In prepanng for final reclamation end plugging and abandonment, the operator shall use its best efforts to consult in good faith vnth 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 liming of such operations and all aspects of final reclamation, including. but not Waded to, the desired final land use and seed ma 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 crepe 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 operabon of equipment is an important part of any safety program. Neale this section is general in nature. It is considered a basic part of the foundation of any safety program a. Employees shall be familiarized vnth these rules and regulations as provided herein as they relate to their function in their respective jobs. Each new employee should have his jcb 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 w$H4tewell stte personnel or to a member of the general public which requires medical treatment or significant damage to equipment or the weitsitewell 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 or 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 ono 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 rcgt iremeds( dement. 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 setbacks. (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. Building Units and Designated Outside Activity Areas are subject to Rule 604. (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. 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. c. Statewide static charge requirements. Rig substructure, derrick, or mast shall be designed and operated to prevent accumulation of static charge. 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. 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 ma,inum anticipated surface pressure and shall be in good waffling 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 Ilne(e) shall be anchored, tied or otherwise secured to prevent whipping resulting from pressure surges. (6) Pressure testing of the casing string end each component of the blowout prevention equipment. if blowout prevention equipment is required, shall be conducted prior to doting out any string of casing except conductor pipe. The minimum test pressure shall be five hundred (500) psiand 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 we closed for any purpose except operational testing. the valves on the choice 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 d 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 dolling rig. 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 maters( 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. 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. 804. LOCATION REQUIREMENTS FOR OIL AND GAS FACILITIES, DRILLING, AND WELL SERVICING OPERATIONS IN DESIGNATED BUFFER ZONES a Designated Buffer Zones (1) Setbacks for Exception Zone,--Any-prepeeed-00 and Gas Location vMn-a-welMaed Locations._After feffecave datel. no Well of Production Facility Fell be located 3888ve hundred (5001 feet or less from a Building Unit shat Icc:.;ir.n except as provided in subsection (3), bete/Rules 604.a.(1) A aosi &And 944.4. A Urban Mitigation Zone Locations The Director shall not approve a Form 2,2 or associated Form 2AZ proposing to locate a wellhead or a production facility within theen Exceptionlpsaand Urban Mitigation Zone unless all Building -U441 ':One consent in writing to the propoc-4U^--c --- Bf aeFwaw00n-Lxllitylles) within the Exe.eptien-Zeno-..and-t o ApplreM: the Operator submits a waiver from ewe nca &ok a_ building tmi or building permitted for construction withirtke.,hvedred (500) feet of the proposed Oil and Gas Location with the Form 39 or .ssoclated Form 2 or obtains a variance pursuant to Rtoe 502Land ii. the Operator certifies it has compiod with Rule 306.e and all applicable safety requirements of the -Odes and reoulatioo and 12) -Buffer Zone. Any proposed.Oil-and-GoHLeeatiesciviha wcW,eadof9ro0uction f—tty le -ledlgne 'wet Or -tees -Ran a Budding Unit shat oonstihfa-> &,Her Zane -Lee tlsn, ijLlhe Form 2A or Form 2 contains conditions of approval sufficient to eliminate jninb06Le_on.nNWate potential adverse impacts to public health, safety, w llace,_theefi(t(QndlefLand mldsfe to the maximum extent technically feasible and eccppinicaly p0lcttr ible Pursuant to Rule 604.c B. Non -Urban Mthaatg ma ) ocatons Except as provided in subsection 604.b. below, the Director shall not approve a Form 2 or Form 2A proposing to locate a wellhead or a production facility within the Buffer Zone until the Applicant-oertiiies n Exception Zone rot in an Urban Mitivation Zone unless the Operator certifies it has complied with Rule 306.e.. and the Form 2A or Form 2 contains conditions of appt ifaLaufident to a rninate minimize or mitioate potential adverse impacts to putt(Ic health safely welfare the emriroanem. and wildlife to the maximum extent tochnicajv feasible any! economically Practicable pursuant to Rule 604.c. %21 Setbacks for Buffer Zone Locations. After leeoc5ve datol. no Well or Production Facility shall be located one thousand 0.000) feet or less from a Budding Unit until the Operator cerllpe4jt has candied with Rule 306.e. and the Form 2A or Form2 tXtmolnesemeieha gj,Approval pursuant to Rule 604.c as necessary to eliminate, minini m or ID'ngate potential adverse impacts to pubic health. safety. welfare. the envirormenl and wildlife (3) High Occupancy Building Unit Zone. Commission approval is required for any Form 2 or Form 2A proposing to locate a wellhead or Production Facility within seven hundred fifty (/50) feet of High Oa estor-may approve a Foos 2 or Form 7A proposing to-IceecEE-w llumolt-ei-pred4Nie4NadNj-wellhead-than seven hundred fifty Vs(l) feet from -a- HgWOoedper.y-&r4ldsig-n4—prov'dod- me Applicant certifies it has complied with Rule 306x.- ifepplioeele-one thousand11.0031 feet of High Occupancy tiuildina Unit. (4) Designated Outside Activity Area Zone. The minimum setback from the boundary of a Designated Outside Activity area shall be three hundred fifty (350) feet The Commission, in its discretion. may establish a setback of greater than three hundred fifty (350) feet based on the totality of circumstances. Mitigation measures pursuant to Rule 60gc, all be required for Oil and Gas Locations within one -thousand f1 000) feet of a Designated Outside Activity Area. b Exceptions -for uExistlng 91l and Gas Locations. The Director may grant an exception to any setback, or consemnotice. censultatip0 or meeting requirement within a Designated Buffer Zone Wren a Well or Production Facility is proposed to be added loan existing or approved Oil and Gas Location if the Director determines alternative locations outside the applicable setback are technically or economically impraGlcabte; mitigation measures imposed in the Form 2 cc Form 2A will eliminate, minimize or mitigate noise. odors, light, dust, and similar nuisance conditions to the reektmen-extent reasonably achievable; the proposed location complies with all other safety requirements of these Commission Rules: and: (MAA.Ag Stagg or acoroved Oil and Gas Location is within a DeaAnated$uller.2QO aotele.as a result d the adootion of Rule 604.a.. abovewhich establishgd.fl 4wislnatss 8LA(er Zones. Q. The Oil and Gas Location is located within a Designated Buffer Zone solely as a result of Building Units constructed after the Oil and Gas Location was approved by the Director; or 0. An existing or approved-Oilena Gas -Le eden4 v fl rna-Ua&gnated-Buffer Zone solely as a result of the adoption of Ride -601.a. above--wlwr, u6t"h'—"'al4lua Designated Buffer &swo- c C A valid StufaSSISgSffeernent executed on or before (effective datel expressly governs the location of Wells oLPlgductlon Pecilitls% on the surface estate and the location required by the Surface Use Agreement encroaches on the setback reouirements in Rule Bogs. (2) Surface Development After fffective datel Pursuant to Surface Use Agreements. Plats and Other Surface PreliMerts. A Surface Owner and mineral comer or lessee may puree to locate future Building Units closer to oxistino or proposed Oil and Gas Locations than other,sse allowed under Rule 604.. pursuant to a valid Surface Use Aareement Prellmina ' Plat Final Plat or Planned Unit Development solely with reflect to the surface galgte.,gpyemed by such SUA PIa . or PUD. All setback, noiIGe. c9oSgllffi!QR and meeting reauirgnpnts Contained in Rules 604.a and 306,e apply with re§pflitte.all Building Units lasted. 00- adlpinlna surface estates that are not governed by the applicable SUA. Dial. or PUD. copies of such Surface Use Agreement. Preliminary Plat Fine) Plat. Planned Unit Developgneel or other surface provision shall be submitted by the Operator with a Form 29 Apcl n nr associated Fonn 2 for a or000sed Oil and Gas Location on the relevant sudaot estate c. Designated Buffer Zone Mitigation Measures. The following rules shall apply In the Exception Zone, the Buffer Zone. wilNin-1000 feet of ads High Occupancy Building Unit Zeta and wdhlo 7.004es4-f-atba Designated Outside Activity Ares Zone: (1) Provisions for future encroaching development tf a location comes within a Designated Buffer Zone solety as a result of surface development after well pad construction begins or production equipment has been placed subsections (6) and (12) shall not apply to the operator. (2) Location Specific Requirements. During Rule 306 consultation, the operator shall develop a location -specific mitigation plan to address the following. A —Daylight Operations. Ind -daylight operations aratu. aired after casing is set. exceptinarnergeasiee-4IwOuector may weave Ihwrcquiremenl d Building- n Zone consent-to-24- Iww"f "her e. —seise. the propoeeb Oil end-Taos—Lecalien—aAalWe determined and reported -to -1 nest of opereliens-+willsheaxy—egrepneM--Uaseene noise levels shall be decibel (dB) scale meesurerrent-eurineLtaylight workieg..nows evening non.aorling—hoero, acme—ekagin8 hours: -Baseline noise data -shalt 3C8,e..oas.. yawns, ir. A. Noise. Operations involving pipeline or gas facaly installation or maintenance, the use of a drilling rig, completion rig. workers( rig. or Stimulation is Subject to the maximum permissible noise levels for Light Industrial Zones, as measured at the newest Building Unit Shod -term increases shall be allowable as descnbed in 802.c For purposes -of -this the no -e 'over s riles measured at x440 the oil and gas operation 6 —Pits. -B. Pit Restrictions Pits are not allowed on Oil and Gas Lgcabons jediti,in Designated Bifler Zones except fresh water storage pits. reserve pits to doll surface casing, and emergency pits as defined in the 100 -Series Rules, pits-erenet-alleweeeo Oil and Gas Locations withiwOesigrated-Beffer-Zoeus , is Fresh water pits within the Exception Zone shall require prior approval of a Form 15 pit permit. In the Biller Zone, fresh water pits shall be reported within 30 - days of pit construction. iv. Fresh water storage pits within the Desgnated Buffer Zones shall be conspicuously posted with signage identifying the pit name. the operators 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 Designated Buffer Zones shall include emergency escape provisions tor inadvertent human access, DSc Emission Control Systems. i. Gas gathenng lines, separators, and sand traps capable ot supporting green completions as described in Rule 805 shall be installed at any Oil and Gas Location at which commercial quantities of gas ere reasonable expected to be produced based on existing adjacent wells within I mile k.ij. Ungontroged venting shall be prohibited in an Urban Ndbation Zone. ii Temporary Ilovrback flaring and oxidizing equipment shall include the following: as Adequately sized equipment to handle 1.5 times the largest 0oeback 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 fueled with sufficient supply and heat to combust or oxidize non- combustible gases in order to control odors and hazardous gases. F.D. Traffic Plan. A traffic plan shall be coordinated vAlh the local jurisdiction prior to commencement of move in and ng up Any subsequent modification to the traffic plan must be coordinated with the local jurisdiction. F E Muhiwell 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 faolihes 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 roe operator and emergency response. (3) A. Blowout preventer equipment ("BOPE") for Designated Buffer Zone drilling operations. Blowout prevention equipment for drilling operations in a Designated Buffer Zone shall consist of (at a minimum): I. Rig with Kelly. Double ran with blind ram and pipe rem; annular preventer cr a rotating head. ii. Rig without Kelly. Double ram with blind ram and pipe ram. Mineral Management certification or Director approved waning for blowout prevention shall be required for at least one (1) person al the well site during drilling operations. B BOPE testing for Designated Buffer Zone drilling operations. Upon initial rig -up and at least once every thirty (30) days during drilling operations thereafter. pressure testing of the casing suing 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%) 01 the internal yield of casing. whichever is less. Pressure testing shall bo conducted and the documented results shall be retained by the operator for inspection by the Director for a period of one (1) year. Activation of the pipe rams for function testing shall be conducted on a daily basis when practicable C. Pit level Indicators. Pit level indicators shall be used. D. Drill stem tests. Closed chamber drill stem tests shall be allowed in Designated Buffer Zones. All other drill Mem tests shall require approval by the Director (4) A. BOPE for well servicing operations. Adequate blowout prevention equipment shall be used on all well servicing operations B. Backup stabbing valves shall be required on well servicing operations during reverse circulation. Valves shall be pressure tested before each well servicing operation using both low•pressure air and high-pressure fluid. (5) Fencing requirements. Unless otherwise requested by the Surface Owner. well sites constructed within Designated Buffer Zones, shall be adequately fenced to restrict access by unauthorized persons. For security purposes. all such facilities and equipment used in the operation of a completed well shall be surrounded by a fence six (6) feet in height, constructed in conformance with local written standards as long as the material is non- combustible and allows for adequate ventilation. and the gate(s) shall be locked. (6) Control of fire hazards. My material not in use that might constitute a fire hazard shall be removed a minimum al twenty-five (25) feet from the wellhead, tanks and separator. Any electrical equipment insralations inside the bermed area shall comply with API RP 500 classifications and compty with the current national electrical code as adopted by the State of Colorado. (7) Loadlines. In Designated Buffer Zones, all loadhnes shall be bullplugged or capped (8) 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. Guy line anchors. Al guy tine anchors left buried for future use shall be identified by a marker of bright color not loss than lour (4) feet in height and not greater than one (1) foot east of the guy line anchor. (10) Berm construction. Berms or other secondary contanment devices in Designated Buffer Zones 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 Noarens-thanivie-(2}rruda-on or condensate storage tanks shelf bc booted withina-singe-bens:-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 Potrolesn Institute Recommended Practices. API RP - D16. (0) A. within.Esception Zones the following mitigation measureswng be mandatory. i No more than two f2Letude oil or condensate storage tanks shall be located within a single berm 0 Containment berms shall be constructed of steel nngs designed and Installed to prevent leakage and resist dedredation from erosion or matins operation is. Secondary containment areas for tanks shall he rnnstiucted with a synthetic or e0g)peered Goer that contains all primary containment vessels and ftgNJnes and is mechanically connected to_Ihgffe(el r=ng_to orevenl leakage (11) Tank specifications. All newly installed or replaced crude oil and condensate storage tanks in Designated Buffer Zones 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. (12) Access roads. If a well site falls within a Designated Buffer Zone 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. (13) 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. (14) Identification of plugged and abandoned wells in Designated Buffer Zones. 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. (15) 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. 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," 11`" Edition (October 2008, effective March 31, 2009); or E. American Petroleum Institute Standard No. 12F, 'Shop Welded Tanks for Storage of Production Uquids,' 12"Edition (October 2008. effective March 31, 2009) (2) Tanks shall be located al least two (2) diameters or three hundred fifty (350) feet. whichever is smatter. 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 (116) the sum of the diameters apart. When the diameter of one tank is less than one-half O/2) the diameter of the adjacent lank, 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 olaced beneath each abu.Y.e.-ground tank such fret any fluid loss from the tank bottom would be tranSOtiged to the Decimeter of the tank. Berms and secondary containment devices and all containment areas shall be sufficiently impervious to contain any spilled or released material. Beans and secondary containment devices shall be Inspected at regular intervals and maintained in good condition. No potential ignition sources shall be installed inside the secondary containment area unless the containment area encloses a fired vessel. (5) Tanks shall be a minimum of seventy-five (75) feet from a fired vessel or heater -treater. (6) Tanks shalt 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 mininum of seventy-five (75) feet from a wellhead (9) Gauge hatches on atmospheric tanks used for crude oil storage shall be closed al all times when not in use (10) Vent lines from individual tanks shall be pined 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 Apra 2, 2008) Only the 5th Edition of the API standard applies to this rule: later amendrnents 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, State 801. Denver. Colorado 80203. In addition. these matenals 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 ono hundred (100) feet from any tank being serviced. (12) Labeling of tanks. Ali tanks and containers shall be labeled in accordance with Rule 210.d. 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 d forty (40) feet from a pump. (4) FV-HT shall be a minimum of seventy-five (75) feet from a well. (6) Al the time of installation. fired vessels end heater treaters shall be a minmum of two hundred (200) feet from residences, building units, cr well defined normally cccupied outside areas. (B) Vents on pressure safety devices shall terminate in a manner so as not to endanger the public or adjdning facilities. They shall be designed so as to be dear and free of debris and water at all times (7) All stacks, vents, or other evenings shall be equipped with screens or other appropriate equipment to prevent entry by vettdfde, 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 twofive hundred (260500) feet of a residence(s). normally occupied Building Units, or well defined normally occupied outside aroa(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 fall 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) Ail pimps, 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 end poses a physical or health hazard. (4) Slgnts) shall be posted at the boundary of the producing site where access exists, identifying the operator, lease name. location. and listing a phone number. induding area code, where the operator may be reached at all times unless emergency numbers have been furnished to the county commission or its designee. 601.r.d. Mechanical Conditions. All valves, pipes and fittings shall be securely fastened. inspected al regular intervals. and maintained in good mechanical condition. ate. Buried or partially burled tanks, vessels, or structures. Buried or partially buried tanks vessels, or structures used for storage of S&P waste shall be properly designed, constructed, installed. and operated in a manner to contain materials safely. A synthetic er engineered liner shall boplaoed beneath. Such vessels shall be tested for leaks after installation and maintained. repaired. or replaced to prevent spills or releases of ESP waste. 1/21f. Produced water pits, special use and burled or partially burled vessels, or structures. At the time of initial construction. pits shall be located not loss than Iw0Jye hundred (200.M1 feet from any building unit 60a. STATEWIDE GROUNOWATER4A-SEUNESAMRLtNG-AND MONITORING. Except coelbed- o-Rule-h0a. new Oil and Ges-Lsxations-shalt-eo subject to the fallow og-g ring requiremena. 4niliv baseline samples and su e collected Nom--two-i2}gr+c-sstrrc$Jor swings within a one (t) mile radius of -the proposed Oil and -Gas -Laeation—Sampimg-frasaicent.4141b8-se+ected by the operator based on thefollowing coterie. (4 -Oct-and-Gas location Water featu keeettee-arerelerFed- (2) Typeof Maier feature Domestic water wellsereptefemdever-elher-watei-featureerSprings maybo-&angled When no water wells we available: (3) Local topographyanMhydreeeetugy,—Greendwa'e' in<I vidare enter flow directions should be assessed in sea oting eampliegiega leer (4Y Orientation-et-k<-se^c v•it iorpoct te-Nw--Oct-and Gas location Where peesb4e-the sampling localionashould-Fame peetecrues-ol1Ne-OJ and Gas location t5) Multiple-iec 14ied-ogwlew-0vail l>0 Where multiple defined aquifere-ere -pwaem—the sampling iorat tram different aquifers when possible isay—E-xisbeibsoinfAs tOCatons Water wells for- data may be JAC- '•. - -Denial of access tosamplog-lesatiener—WhOW-the owners of all snnable-sampli g -lessens refuse to grant access-dccpileenopembes'cbesFallerts-to cbtain consent to conduct sompi.ng. the Uueotor may mod4yerweivethe-wgdirweentsofll *Rule -600. c Timing-eftnl ing shall becoodueted- t-It Prat 'a aAmn xroement of drillino es, -on Oil-and-Ges-Les b .w-w1w e -no wells are planned. plrpc ie-OffmiaOacemem of insiailation can -9d Jn66as-Fas4l4 aloe tgraPMr-alai (2) Prior to re-slineeal:en-e-4-avieg-it-otieha than twelve 112) months-hove-pesced+Mwothe+rwww4 pis-dritsng sampling evert+" tap rr^c''oce^4aesunnael•4n sampling event wesoeodeeted, d Subsequentmoeitegngoampling:- Subseni,ent- fit Net Bess ihan-t2-mewN»rreR-ruorettian 18 months, fol ova _ y in taavien and (2)Netkcc urn c'-ty (80r- then -nor -more -Ian seventy-eight (78) month- aRa-Hte-toret cempling-eweel-peiferniedHnasnanlio elide 60g d ( I ) (3) Addt,onal'post-oanH Yen to ,t(c) maybe -gated 4 Ozni,iiii.avnner quality are identified during lollrnv-up testing (4) The-Directer-rnay-iesune-kelheewatel-well sampling at any time in response to compaints from' waterwell-ow ners, e Sampling proceduresandanalyNsak (I-)- - lacatifixmance wnh an accepted -industry standard as<. 810 b 2): (21 rho vWial-baseu're testing descnbed in this section shall-incl total-dis:dved-eoho6 (HIS) dissdNed gases (methane. ethane. propane}.-elkaWery-(1et01 bicarborsale-aMurbooate-as-CaCO3) major anions (bromide. cfonde, fluwMe.-.w*ate: nilreta- 444o.as-N;.pbesphatas}; major-CO4IOns (calcium, iron magnesium, manganese: potassium; beam, selenium and strontium), presence of bacteria (iron +stated --mate rcdusag, Hire and troilism). totot-petrole'.n hydrocarbons (TPH) and BTEX compounds (benzene - Weeper Hydrogen sulfide shall also be measured using -a Held odor, water -color sediment, boobies. and efie k)caeon shall be Surveyed -in accordeoeevrit Ii#FJhOlateel veno-on of F.PA SW 8cS anaytical methods -be- r •a' cy'^6"b'e--^d Ir.i ^^a'y..^s of saa>Mseoe$edomied by laboratones that frainfainetefeetnahonaleneretlitatierepregiame- (3) If free gas Or-ra-d,eso 'ed-methklnew ' ' t a g .weer -than I 0 md4aram per liter (mgd) i5 detected in a water well. gee c ' ale- 404)043s -analysis of the me(nane (carbon and hydrogen - i2G.-13C, 711 &d'1') 6h - t -"u p •d9aned4460WI a14e9as type-.It.teet/esnks tndcated ihem'agenic or -a mixture -of -1h nevem' mr 4-,r&C ace 8 Use-mothanckencetitiatiantnoreasee by mote than 5.0 mgn-between-60R44419-periods,-ar le veve-hsan-40-nrg:1, the operator shall notify the Due;tor-...J-9 waae'-woHwnediatelp t4 —G,opee-otal110st results described ebovesbadbe the -water well owner within three (3) months-of-wuc:bri the-sauwb—the analyhc.'v data and asveyea well locations shall else-te .aline: A to ,he 0lt0ohf iii-an-a4.rtron,c data (Washable tomcat. 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 othor downstream 'gas fao4ties' (See definition In the 100 Series of these rules). $Q2.b. On and gas operations al any well site, production facility. or gas faoliy 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)B, 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). I802A. In situations where the complaint or Commission ensite inspection indicates that low frequency noise is a component of the problem, the Commission shall obtain a sound level measurement twenty-fwe (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 operate to obtain a low frequency noise impact analysis by a qualified sound expert. including identification of any reasonable control measures available to mitigate such ion frequency noise impact Such study shall be provided to the Commission for consideration and possible action 1692..e. Exhaust from all engines. motors. coolers and other mechanized equipment shall be vented in a direction away from all building units. 18021 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. UGHTING 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. con -contrasting. non -reflective color tones (similar to the Munsell Sal Color Coding System), and with colors matched to but slightly darker than the surrounding landscape. 808. ODORS AND DUST 1805.a. General. Oil and gas took -ties and equipment shall be operated in such a manner that odors and dust do not constitute a nuisance or hazard to public welfare. 1805.b. Odors. (7y 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. 1001-51 and Regulation No. 7 Section XVII B 1 fast B. No violation c4 Rule 805O.(1) shall be cited by the Commission, provided that the practices identified in Rule 805.b.(2) am used. (2) Production Equipment and Operations. A. Crude Oil, Condensate, and Produced Water Tanks. All crude oil, condensate, and produced wafer tanks with a potential -lo eatilagggnirrraled actual emissions volatile organic compounds (VOC) of five (5) tons per year (tpy) or greater, located in-a-Dee.gnated Buffer Zone-(Rtais-Gor-tvatitt-4400tyliffijlag feet of a FNgh-Occupancy Building Unk{Ruk-b0&4}, or a Designated Outside Activity Area shall use an emission control device capable of achieving 95% control efficiency of VOC and shall hol dobtain a valid permit hem-IHeasjygyl0x1 b�( Colorado Department of Public Health and Environment Air Pollution Control Divisicnrfar-the-taekCommissan Reaulation No. 3 f5CCR 1001-51 and central device.-Reouiation No. 7 $actlen XVII. B 1 fa -el. B. Glycol Dehydrators. All glycol dehydrators with a 6areWial-1P-entnuncontrolled actual emissions VOC of Ike (5) tpy or greater. located in -a Des,gnaled-8aper lone (Rule 604.an; or -within d000U2(i feet of a High Occupancy-Buil6ng Unit (Rule 604 b) , or a Designated Outside Activity Area shall use an emission control device capable of achieving 90% control efficiency of VOC and shall heldobtaq a valid permit Irom Iheas reouired by Colorado Department of Public Health and Environment, Air Pollution Control Dakeen—far-44*-gfycal dehydratorConmission Reaulab4n_ No 3 (5CCR 100151 and sentrei deviceReoulation No. 7 $,4QjpfXVll A t (ac) C. Pits. Pits with a potential to emit VOC of five (5) tpy or greater shall not be located within a-Desigeated-13Wfer4oaeale 604 a.). or within 10001 feet alai -4h Occupancy Building Unit-(Ret4-6940:;, 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 productivityand 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) prig or sales line pressure. v,ichever is greater. Green ccmplebon practices are not required for exploratory wells. where the wells are not sufficiently proximate to sales lines, or whore 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 won as practicable dunng flowback end 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. DRAFT December 31, 2012 (STAKEHOLDER DRAFT REVISION 1) DEFINITIONS (100 Series) Application for Development shall have the meaning set forth in C.R.S. § 24-65.5-102(2)(a). Buffer Zone Location. Any proposed Oil and Gas Location with a wellhead or production facility located one thousand (1,000) feet or less from a Residential Building Unit shall constitute a Buffer Zone Location. The measurement for of determining the Buffer Zone shall be made from the wellhead or Production Facility nearest any Building Unit to the nearest wall or corner of such Building Unit. Designated Buffer Zone Locations shall mean any Oil and Gas Location within, or proposed to be constructed within a Buffer Zone Location, Exception Zone Location, 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. Designated Outside Activity Area: Upon Application and Hearing, the Commission, in its discretion, may establish a Designated Outside Activity Area (DOAA) for: (a) 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 (b) 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 located 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. Exception Zone Location. Any proposed Oil and Gas Location with a Well or Production Facility located five hundred (500) feet or less from a Residential Building Unit shall constitute an Exception Zone Location. The measurement for of determining the Exception Zone shall be made from the wellhead or Production Facility nearest any Building Unit to the nearest wall or corner of such Building Unit. High Occupancy Building Unit shall mean: (a) 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 (b) an operating Child Care Center as defined in C.R.S. § 26-6-102(1.5). Residential Building Unit shall mean [to be defined] Surface Owner shall mean the owner of the surface estate upon which a Well, Production Facility, Oil and Gas Location, or Oil and Gas Facility is located or proposed to be located pursuant to a Form 2 or Form 2A. Surface Use Agreement shall mean a valid contract between an Operator and a Surface Owner, or their respective predecessors in interest, that governs, in whole or in part, Oil and Gas Operations on the surface estate. Urban Mitigation Zone shall mean any area in which: (A) at least twenty-two (22) Building Units or one (1) High Occupancy Building Unit exist or are under construction within a 72 -acre circle having a radius of 1,000 feet measured from any wellhead or Production Facility to the nearest wall or corner of any Building Unit; or (B) at least eleven (11) Building Units or one (1) High Occupancy Building Unit exist or are under construction within a 36 acre semi -circle of the same radius. An Urban Mitigation Zone shall be determined at the time a Form 2A or Form 2 is submitted. 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 operationally conflicting local governmental permit or land use approval process. (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 proposed wellhead. (6) Information Requirements. Attached to and part of the Form 2, Application for Permit -to - Drill, as filed shall be a current 8%" 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 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 buildings or residences, publicly maintained roads and trails, major above -ground utility lines, railroads, pipelines, mines, oil wells, gas wells, injection wells, water wells known to the operator and those registered with the Colorado State Engineer, known springs, plugged wells, known sewers with manholes, standing bodies of water, and natural channels including permanent canals and ditches through which water may flow. A description of surface uses within the 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: A scaled facility layout drawing depicting the location of all existing and proposed new Oil and Gas Facilities listed on the Form 2A; and i. A Waste Management Plan describing how the Operator intends to satisfy the general requirements of Rule 907.a. K. If the proposed Oil and Gas Location is within an Urban Mitigation Zone, evidence that the local government received the Local Government Advance Notice required by Rule 305.d.(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. 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. 303.1. 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 POSTING, COMMENT, APPROVAL, AND NOTIFICATION a. 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.b. 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.a, 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.e. (2) For Oil and Gas Locations proposed within an Exception Zone or Buffer Zone, 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.c. Conditions of approval; issuance of permit. 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 with standing to do so requests a hearing before the Commission pursuant to Rule 503.b on an Application for Permit -to -Drill, Form 2, or Oil and Gas Location Assessment, Form 2A, then it shall notify the Director in writing within ten (10) days after the issuance of the decision, setting forth the basis for the objection. Upon receipt of such an objection, the Director shall suspend the approval of the Form 2 or Form 2A and set the matter for an expedited adjudicatory hearing. Such a hearing shall be expedited but will only be held after both the 20 days' notice and the newspaper notice are given as required by Section 34-60-108, C.R.S. However, the hearing can be held after the newspaper notice if all of the entities listed under Rule 503.b waive the 20 - day notice requirement. If such an objection is not received, the permit shall issue as proposed by the Director. (3) Appeal. If the approval of a Form 2 or Form 2A is not suspended as provided for herein, the issuance of the approved Form 2 or Form 2A by the Director shall be deemed a final decision of the Commission, subject to judicial appeal. 305.d. Notice (1) Local Government Advance Notice. For Oil and Gas Locations within the Urban Mitigation Zone, an Operator shall notify the local government in writing that it intends to apply for an Oil and Gas Location Assessment not less than thirty (30) days prior to submitting a Form 2A to the Director. Such Advance Notice shall be provided to the Local Governmental Designee in those jurisdictions that have designated and LGC, and to the planning department in jurisdictions that have no LGD. Such Advance Notice shall include a general description of the proposed Oil and Gas Facilities, the location of the proposed Oil and Gas Facilities, and the anticipated date operations will commence. This Advance Notice shall serve as an invitation to the Local Governmental Designee to engage in discussions with the Operator regarding proposed operations and timing, and to notify the Operator of opportunities for collaboration with local government agencies or other Operators, and of local government jurisdictional requirements. 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) Surface Owner Notice. 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. A. Surface Owner Notice is not required on federal- or Indian -owned surface lands B. 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. C. The Surface Owner Notice must provide: i. The operator's name and contact information for the operator or its agent; ii. A site diagram or plat of the proposed well location and any associated roads and production facilities; iii. The date operations with heavy equipment are expected to commence; iv. A copy of the COGCC Informational Brochure for Surface Owners; v. A postage -paid, return -addressed post card whereby the Surface Owner may request consultation pursuant to Rule 306; and, vi. 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. (3) Oil and Gas Location Assessment Notice ("OGLA Notice"). Upon receipt of a completeness determination from the Director, the Applicant for an Oil and Gas Location Assessment, Form 2A, shall promptly provide the information described below to the following parties: A. Parties to be noticed: Owners of all Building Units within the Exception Buffer Zone; and ii. 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; 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: The Form 2A itself (without attachments); H. 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. (4) Buffer Zone Notice. Notice 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; 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. (5) 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. (6) 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. Notice of subsequent well operations. An Operator shall provide to the Surface Owner or agent at least seven (7) days advance notice of subsequent well operations with heavy equipment that will materially impact surface areas beyond the existing access road or well site, such as recompletion or refracturing of the well. (7) (8) 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. (9) 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. (10) 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.e. 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. An Operator shall meet or consult with the following persons: 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 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, local jurisdictional issues, including land use, 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.a, 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 Exception Zone or Urban Mitigation Zone Oil and Gas Locations, the LGD may request that the operator hold informational meetings for Building Unit owners within those Buffer Zones. Such informational meetings may be held on an individual basis, in small groups, or in larger community meetings. If an operator chooses to hold community meetings, at least two meetings shall be held at times that allow persons who have regular work schedules (between 8:00 a.m. and 6:00 p.m.) to attend and at a location convenient to attendees. 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 Buffer Zone; 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: 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. (1) Exception Zone. For Oil and Gas Locations proposed within an Exception Zone, the operator shall meet and confer with Building Unit Owners who received the OGLA Notice pursuant to Rule 305.e.(2). Such conferences may be held on an individual basis, in small groups, or in larger community meetings. If an operator chooses to hold community meetings, at least two meetings shall be held at times that allow persons who have regular work schedules (between 8:00 a.m. and 6:00 p.m.) to attend and at a location convenient to attendees. The Operator shall discuss the subjects identified in subsection (3), below. Operators shall consider and address legitimate public health, safety and welfare concerns identified by the Building Unit owners through design and implementation of Best Management Practices or mitigation measures in consultation with the Director. (2) Buffer Zone. An Operator shall be available to meet with Building Unit owners who received a Buffer Zone Notice pursuant to Rule 305.e.(3) and who request a meeting regarding the proposed Oil and Gas Location or Facilities. Operators shall also be available to meet with Building Unit owners if requested to do so by the Local Governmental Designee. Such informational meetings may be held on an individual basis, in small groups, or in larger community meetings. If an operator chooses to hold community meetings, at least two meetings shall be held at times that allow persons who have regular work schedules (between 8:00 a.m. and 6:00 p.m.) to attend and at a location convenient to attendees. The Operator shall discuss the subjects identified in subsection (3), below. (3) Information provided by operator. When meeting with Building Unit owners or their appointed agent(s) pursuant to subsections (1) and (2), above, the Operator shall provide the following information no sooner than 90 days prior to drilling and not later than 30 days prior to drilling: 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. (4) Waiver. The Building Unit owner or agent may waive 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. (5) 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. (6) Operator Certification. The Director shall not approve a Form 2A, Oil and Gas Location Assessment, until either: A. The operator certifies it has complied with the meeting requirements of this Rule 306.e; or B. As a condition of approval on a Form 2A, the Director requires the Operator to hold the required informational meetings by the timeframes identified in subsection 306.e.(3), above and promptly thereafter to submit a Sundry Notice, Form 4, certifying compliance with this Rule 306.e. and including any resultant mitigation measures or Best Management Practices. 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 setbacks. (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. Building Units and Designated Outside Activity Areas are subject to Rule 604. (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. 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. c. Statewide static charge requirements. Rig substructure, derrick, or mast shall be designed and operated to prevent accumulation of static charge. 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. 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. 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. (5) (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. 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. 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. LOCATION REQUIREMENTS FOR OIL AND GAS FACILITIES, DRILLING, AND WELL SERVICING OPERATIONS IN DESIGNATED BUFFER ZONES a. Designated Buffer Zones (1) Setbacks for Exception Zone Locations. After [effective date], 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 Zone Locations. The Director shall not approve a Form 2A or associated Form 2 proposing to locate a wellhead or a production facility within an Exception Zone and Urban Mitigation Zone unless: the Operator submits a waiver from each person owning a building unit or building permitted for construction 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 Rule 306.e. and all applicable safety requirements of the rules and regulation; and hi. the Form 2A or Form 2 contains conditions of approval 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 pursuant to Rule 604.c. B. Non -Urban Mitigation Zone Locations. Except as provided in subsection 604.b., below, the Director shall not approve a Form 2 or Form 2A proposing to locate a wellhead or a production facility within an Exception Zone not in an Urban Mitigation Zone unless the Operator certifies it has complied with Rule 306.e., and the Form 2A or Form 2 contains conditions of approval 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 pursuant to Rule 604.c. (2) Setbacks for Buffer Zone Locations. After [effective date], 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 pursuant to Rule 604.c as necessary to eliminate, minimize or mitigate potential adverse impacts to public health, safety, welfare, the environment, and wildlife. (3) High Occupancy Building Unit Zone. Commission approval is required for any Form 2 or Form 2A proposing to locate a wellhead or Production Facility within one thousand (1,000) feet of High Occupancy Building Unit. (4) Designated Outside Activity Area Zone. The minimum setback from the boundary of a Designated Outside Activity area shall be three hundred fifty (350) feet. The Commission, in its discretion, may establish a setback of greater than three hundred fifty (350) feet based on the totality of circumstances. 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. b. Exceptions (1) Existing Oil and Gas Locations. The Director may grant an exception to any setback, or notice, consultation or meeting requirement within a Designated Buffer Zone 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 Buffer Zone solely as a result of the adoption of Rule 604.a., above, which established the Designated Buffer Zones; B. The Oil and Gas Location is located within a Designated Buffer Zone solely as a result of Building Units constructed after the Oil and Gas Location was approved by the Director; or C. A valid Surface Use Agreement, executed on or before [effective date], expressly governs the location of Wells or Production Facilities on the surface estate and the location required by the Surface Use Agreement encroaches on the setback requirements in Rule 604.a. (2) Surface Development After [effective date] Pursuant to Surface Use Agreements, Plats and Other Surface Provisions. A Surface Owner and mineral owner or 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, Preliminary Plat, Final Plat, or Planned Unit Development solely with respect to the surface estate governed by such SUA, Plat, or PUD. All setback, notice, consultation and meeting requirements contained in Rules 604.a and 306.e apply with respect to all Building Units located on adjoining surface estates that are not governed by the applicable SUA, Plat, or PUD. Copies of such Surface Use Agreement, Preliminary Plat, Final Plat, Planned Unit Development, or other surface provision 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. c. Designated Buffer Zone Mitigation Measures. The following rules shall apply in the Exception Zone, the Buffer Zone, the High Occupancy Building Unit Zone, and the Designated Outside Activity Area Zone: (1) Provisions for future encroaching development. If a location comes within a Designated Buffer Zone solely as a result of surface development after well pad construction begins or production equipment has been placed, subsections (5) and (12) shall not apply to the operator. (2) Location Specific Requirements. During Rule 306 consultation, the operator shall develop a location -specific mitigation plan to address the following: A. Noise. 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 Light Industrial Zones, as measured at the nearest Building Unit. Short-term increases shall be allowable as described in 802.c. B. Pit Restrictions. i. Pits are not allowed on Oil and Gas Locations within Designated Buffer Zones, 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 Designated Buffer Zones 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 Designated Buffer Zones shall include emergency escape provisions for inadvertent human access. C. Emission Control Systems. i. Gas gathering 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 reasonable expected to be produced based on existing adjacent wells within 1 mile. ii. Uncontrolled venting shall be prohibited in an Urban Mitigation Zone 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 fueled with sufficient supply and heat to combust or oxidize non- combustible gases in order to control odors and hazardous gases. D. Traffic Plan. 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. (3) A. Blowout preventer equipment (`ROPE") for Designated Buffer Zone drilling operations. Blowout prevention equipment for drilling operations in a Designated Buffer Zone 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. B. BOPE testing for Designated Buffer Zone drilling operations. Upon initial rig -up and at least once every thirty (30) days during drilling operations thereafter, pressure testing of the casing string and each component of the blowout prevention equipment including flange connections shall be performed to seventy percent (70%) of working pressure or seventy percent (70%) of the internal yield of casing, whichever is less. Pressure testing shall be conducted and the documented results shall be retained by the operator for inspection by the Director for a period of one (1) year. Activation of the pipe rams for function testing shall be conducted on a daily basis when practicable. C. Pit level indicators. Pit level indicators shall be used. D. Drill stem tests. Closed chamber drill stem tests shall be allowed in Designated Buffer Zones. All other drill stem tests shall require approval by the Director. (4) A. BOPE for well servicing operations. Adequate blowout prevention equipment shall be used on all well servicing operations. B. Backup stabbing valves shall be required on well servicing operations during reverse circulation. Valves shall be pressure tested before each well servicing operation using both low-pressure air and high-pressure fluid. (5) Fencing requirements. Unless otherwise requested by the Surface Owner, well sites constructed within Designated Buffer Zones, shall be adequately fenced to restrict access by unauthorized persons. For security purposes, all such facilities and equipment used in the operation of a completed well shall be surrounded by a fence six (6) feet in height, constructed in conformance with local written standards as long as the material is non- combustible and allows for adequate ventilation, and the gate(s) shall be locked. (6) 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. (7) Loadlines. In Designated Buffer Zones, all loadlines shall be bullplugged or capped. (8) (9) 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. 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. (10) Berm construction. Berms or other secondary containment devices in Designated Buffer Zones 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. A. Within Exception Zones, the following mitigation measures will be mandatory: i. No more than two (2) crude oil or condensate storage tanks shall be located within a single berm. H. Containment berms shall be constructed of steel rings, designed and installed to prevent leakage and resist degredation from erosion or routine operation. Hi. 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. (11) Tank specifications. All newly installed or replaced crude oil and condensate storage tanks in Designated Buffer Zones 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. (12) Access roads. If a well site falls within a Designated Buffer Zone 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. (13) 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. (14) Identification of plugged and abandoned wells in Designated Buffer Zones. 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. (15) 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. 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," 11`" Edition (June 2007); C. American Petroleum Institute Standard No. 12B, "Bolted Tanks for Storage of Production Liquids," 15`" Edition (October 2008, effective March 31, 2009); D. American Petroleum Institute Standard No. 12D, "Field Welded Tanks for Storage of Production Liquids," 11`" Edition (October 2008, effective March 31, 2009); or E. American Petroleum Institute Standard No. 12F, "Shop Welded Tanks for Storage of Production Liquids," 121h 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 beneath each above -ground tank such that any fluid loss from the tank bottom would be transmitted to the perimeter of the 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. (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 (TACT). (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 residence(s), normally occupied Building Units, or well defined normally occupied outside area(s), shall be equipped with an automatic control valve that will shut the well in when a sudden change of pressure, either a rise or drop, occurs. Automatic control valves shall be designed so they fail safe. (2) Pressure control valves required in (a) shall be activated by a secondary gas source supply, and shall be inspected at least every three (3) months to assure they are in good working order and the secondary gas supply has volume and pressure sufficient to activate the control valve. (3) All pumps, pits, and producing facilities shall be adequately fenced to prevent access by unauthorized persons when the producing site or equipment is easily accessible to the public and poses a physical or health hazard. (4) Sign(s) shall be posted at the boundary of the producing site where access exists, identifying the operator, lease name, location, and listing a phone number, including area code, where the operator may be reached at all times unless emergency numbers have been furnished to the county commission or its designee. 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 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)B, 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 io (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). 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 a uncontrolled actual emissions 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 No. 3 (5CCR 1001-5) and Regulation No. 7 Section XVII.B.1 (a -c). B. Glycol Dehydrators. All glycol dehydrators with a uncontrolled actual emissions 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 No. 3 (5CCR 1001-5) and Regulation No. 7 Section XVII.B.1 (a -c). C. Pits. Pits with a potential to emit VOC of five (5) tpy or greater shall not be located within 1,32 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. Hello