CITY OF THORNTON CITY MANAGER’S OFFICE

COUNCIL UPDATE July 26, 2016

5:45 p.m. Training Room

I. DISCUSSION ITEMS

II. COUNCIL MEETING AGENDA ITEMS

A. An ordinance amending Section 38-1 pertaining to the definition of

solicitor and canvasser, 38-180, 38-207 and 38-213 pertaining to regulation of solicitors generally and on streets, highways, sidewalks, and public place of the Thornton City Code

B. An ordinance amending Section 2-1 of the Thornton City Code pertaining

to implementation of the City Charter changes concerning publication of legal notices and making conforming amendments throughout the Code

III. COUNCIL INFORMATION SHARING

A. DRCOG Board of Directors Meeting (7/20) Update by Councilmember Matkowsky

B. Rangeview Library District Meeting (7/20) Update by Councilmember Nizam

IV. CONTINUATION OF COUNCIL UPDATE

A. Update on Oil and Gas Development Regulations

B. Discussion of the Oil and Gas Traffic Impact Fee Study

A

INTRODUCED BY: AN ORDINANCE AMENDING SECTION 38-1 PERTAINING TO THE DEFINITION OF SOLICITOR AND CANVASSER, AND SECTIONS 38-180, 38-207, AND 38-213 PERTAINING TO REGULATION OF SOLICITORS GENERALLY AND ON STREETS, HIGHWAYS, SIDEWALKS, AND PUBLIC PLACES OF THE THORNTON CITY CODE. WHEREAS, the City regulates soliciting or canvassing pursuant to Section 38-180 and defines those terms in Section 38-1 definitions; and WHEREAS, the City regulates solicitation on streets or highways pursuant to Subsections 38-207 (a) and (d); and WHEREAS, the City also regulates solicitation on public sidewalks and other public places pursuant to 38-213; and WHEREAS, in a recent decision the United States Supreme Court ruled that any ordinance that regulates speech or conduct based on the content of the message expressed is unconstitutional; and WHEREAS, when the City exercises its police power to protect and promote the public health, safety and welfare, it must do so within constitutional standards established by the U.S. Supreme Court; and WHEREAS, amendments to Sections 38-1, 38-180, 38-207, and 38-213 of the Code regarding the regulations of canvassers and solicitors are necessary to regulate only conduct and not conduct based upon any type of speech; and WHEREAS, the City finds these amendments are necessary to regulate conduct that may threatened the public safety, safety and welfare. NOW, THEREFORE, BE IT ORDAINED BY THE CITY COUNCIL OF THE CITY OF THORNTON, COLORADO, AS FOLLOWS: 1. Section 38-1 is hereby amended by the addition of the words double-underlined

and the deletion of the words stricken to read as follows:

Sec. 38-1. Definitions.

Canvasser means any individual, whether a resident of the City or not, who travels from private residence to private residence for public, political, religious or social purposes, but does not include solicitor. Solicitor or peddler means any individual, whether a resident of the city or not, who engages in or attempts to engage in any type of contact for solicits for contributions or for the purchase or sale of goods or services of any natureany

2

purpose whatsoever from at a point of entry to any private residence.

2. Section 38-180 and subsections (a) and (b) are hereby amended by the deletion of the words stricken to read as follows:

Sec. 38-180. No soliciting or canvassing.

(a) It shall be unlawful for any solicitor or canvasser to solicit or canvass at a private residence whereon a sign has been conspicuously displayed with the words "no solicitors" or "no soliciting."

(b) It shall be unlawful for any canvasser, peddler or solicitor to remain on a private residence after the occupant requests the canvasser, peddler or solicitor to leave, whether or not any "no solicitors" or "no soliciting" signs have been displayed.

3. Subsection 38-207 (a) and (d) are hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows:

Sec. 38-207. Blocking streets or sidewalks; solicitation on streets or highways. (a) The purpose of this section is to prevent dangers to persons, including

juveniles placed in hazardous situations, and to property, to prevent delays, and to avoid interference with pedestrian and traffic flow. Roadways that have center medians are designed to deal with specific traffic flow problems not for the solicitation or selling of goods. Any delay or distraction to motorists traveling on such roadways or highways may interfere with traffic planning. Sidewalks are designed to transport pedestrians safely and efficiently and any obstruction that impedes travel disturbs planned pedestrian flow.

(d) It shall be unlawful for any person to to solicit or attempt to solicit employment

or contributionsengage in or attempt to engage in any type of contact or conduct business of any kind and for any purpose from or with an occupant of any vehicle on any street, roadway or highway included in the interstate system, including any entrance to or exit from such highway.

4. Section 38-213 is hereby amended by the addition of the words double-underlined

and the deletion of the words stricken to read as follows:

Sec. 38-213. Unlawful disturbance or obstruction by vendors. It shall be unlawful for any person engaged in any type of activity the sale of newspapers, magazines or other goods or merchandise to make any unnecessary sound or noise, which in any way to obstructs any sidewalk or other public place or to disturb or impedes others from using a sidewalk or other public place.

3

5. If any portion of this ordinance is held to be unconstitutional or invalid for any reason, such decision shall not affect the constitutionality or validity of the remaining portions of this ordinance. City Council hereby declares that it would have passed this ordinance and each part hereof irrespective of the fact that any one part be declared unconstitutional or invalid.

6. All other ordinances or portions thereof inconsistent or conflicting with this

ordinance or any portions hereof are hereby repealed to the extent of such inconsistency or conflict.

7. The repeal or amendment of any provision of the Code by this ordinance shall

not release, extinguish, alter, modify, or change in whole or in part any penalty, forfeiture, or liability, either civil or criminal, which shall have been incurred under such provision, and each provision shall be treated and held as still remaining in force for the purpose of sustaining any and all proper actions, suits, proceedings, and prosecutions for the enforcement of the penalty, forfeiture, or liability, as well as for the purpose of sustaining any judgment, decree, or order which can or may be rendered, entered, or made in such actions, suits, proceedings, or prosecutions.

8. This ordinance shall take effect upon final passage. INTRODUCED, READ, PASSED on first reading, ordered posted in full, and title ordered published by the City Council of the City of Thornton, Colorado, on , 2016. PASSED AND ADOPTED on second and final reading on , 2016. CITY OF THORNTON, COLORADO Heidi K. Williams, Mayor ATTEST: Nancy A. Vincent, City Clerk

THIS ORDINANCE IS ON FILE IN THE CITY CLERK’S OFFICE FOR PUBLIC INSPECTION. APPROVED AS TO LEGAL FORM: Gary G. Jacobson, Interim City Attorney PUBLICATION: Posted in six (6) public places after first and second readings. Published in the Northglenn-Thornton Sentinel after first reading on , 2016, and after second and final reading on , 2016.

B

COUNCIL UPDATE COMMUNICATION PAGE 2

Section 2-1(a) is changed to allow Notice to be provided by different means of publication rather than exclusively by a newspaper. Section 2-1(b)(1) says that the term for the designation of any means of publication shall be fixed by the City Manager for no more than a five years and (b)(2) gives the City Manager the authority to designate any alternative means of publication as provided if a legal newspaper fails to meet application eligibility standards or a conflict of interest arises. Section 2-1(c) states that the intent of the City Council in establishing the means of publication is to serve the public interest by providing an accurate and reliable resource to the residents and businesses of the City to ensure that responsible and representative government is maintained. It also gives City Council the right to terminate or suspend the means of publication by resolution and by resolution select an interim means of publication. Thornton’s prior publication requirements for government notices had become outdated. The City has historically chosen a newspaper as the exclusive means of publication and has used a local newspaper for that purpose. Due to declining subscriptions for local newspapers as well as the advent of notice by electronic means, the Charter was amended to allow more flexibility in establishing various means of publication rather than relying simply on newspapers with declining subscriptions and penetration. Additionally, electronic communications have become more pervasive and adopted widely among a diverse range of people, including Thornton residents and businesses. Providing for a wide range of communication platforms for finding this information provides for a greater level of transparency.

INTRODUCED BY: AN ORDINANCE AMENDING SECTION 2-1 OF THE THORNTON CITY CODE PERTAINING TO IMPLEMENTATION OF THE CITY CHARTER CHANGES CONCERNING PUBLICATION OF LEGAL NOTICES AND MAKING CONFORMING AMENDMENTS THROUGHOUT THE CODE. WHEREAS, Section 2-1 of the Thornton City Code contains the requirements for legal notices to be published as required by the Charter, the Thornton City Code and other applicable laws; and WHEREAS, the Thornton City Charter has recently been amended to remove all references to a newspaper as the exclusive means of publication; and WHEREAS, this change has necessitated amending Section 2-1 and establishing various other means of publication meeting applicable requirements for publication; and WHEREAS, other references to publication by newspaper as the exclusive means of publication throughout the Thornton City Code have to be amended to conform to the current Charter. NOW, THEREFORE, BE IT ORDAINED BY THE CITY COUNCIL OF THE CITY OF THORNTON, COLORADO, AS FOLLOWS:

1. The title to Section 2-1 and Subsection 2-1(a) are hereby amended by the addition of the words double-underlined and the deletion of the words stricken and Subsection 2-1(a)(4) is hereby deleted to read as follows: Sec. 2-1. Legal notices and advertisements. (a) Whenever a legal notice or advertisement is required to be published by the

Charter, this Code or ordinances of the city or applicable laws or regulations of the state or United States, unless otherwise therein set forth, such notice or advertisement shall be published at least once in a newspaper having general circulation in the city and meeting using any of the following minimum standardsmeans of publication; as authorized by Section 2-1(b)(2):

(1) The A newspaper shall be that is published on fixed days or dates at least

once each week and at regular intervals, shall be a publication devoted to the general dissemination of local, or local, state, national or international news, and shall not include publications such as trade journals or other special publications addressed primarily to any special group or interest.

(2) Such legal newspaper shall otherwise conform to the requirements set

forth by state law, C.R.S. Tit. 24, Art. 70, Pt. 1 (C.R.S. § 24-70-101 et seq.

2

and C.R.S. § 31-16-105), concerning the requisites for legal notices, unless otherwise provided in this section.The city's official web site is an authorized means of publication which notice will remain on the web page until the event noticed and which posting shall meet the applicable requirements for the duration of the notice prior to the event noticed. The city's public government cable access Cchannel 8 is also an authorized means of publication so long ats the broadcast meets the minimum frequency requirements as set for herein for the city’s web site and the broadcast begins and continues for the required duration of the notice prior to the event noticed.

(3) Any other applicable electronic, analog, or digital mediums may be used

as a means of publication, if specifically approved by the city manager, and such mediums meet the minimum applicable frequency and duration requirements for the event noticed. The publication of such legal newspaper shall be a secular publication devoted to the general dissemination of general local, or local, state, national and international news, and shall not include publications such as trade journals or other special publications addressed primarily to any special group or interest.

(4) Such legal newspaper shall be distributed throughout the city and shall at

all times have a regular, effective and continuing distribution to residential and commercial properties of not less than 20 percent. Such minimum penetration standard for a period of the immediately next preceding 12-month period shall be a condition of bidding and continuing eligibility to serve as the legal newspaper, as contemplated in this section. However, the validity of any ordinance published in conformance with the standards of state law shall not be rendered ineffective or subject to legal challenge due to the failure of the newspaper to achieve or maintain the minimum distribution level set forth in this subsection.

(2) Subsection 2-1(b) is hereby amended by the addition of the words double-

underlined and the deletion of the words stricken to read as follows:

(b) The legal newspaper shall be designatedAny means of publication by an entity other than the city shall be in substantial compliance with the public bidding criteria set forth in Article III of Chapter 26 governing purchasing by the city, subject to the following:

(1) The term of thefor the designation of the any means of legal newspaper publication shall be fixed by the city manager; however such term shall not exceed a period of five years.

(2) The newspaper designated as the legal newspaper of the city, during the term of the contract for providing public

3

notice, shall be the exclusive legal newspaper. The city manager shall, notwithstanding, have the authority to appoint an additional or substitute legal newspaper designate any alternative means of publication as provided for herein if a legal newspaper fails to meet applicable otherwise meeting the eligibility criteria set forth in this section in the event of a failure of eligibility standards set forth in Section 2-1(a)(1), cessation ofceases publication for any time or reason, the timing of publication does not meet the requirements of the law, or a conflict of interest or the appearance of such conflict arises or if for any matter a or a greater penetration or area of distribution is deemed to serve the public interest, in which event such publication shall occur in the other newspaper selected ad hocbe met by any designated alternative means of publication.

(3) Subsection 2-1(c) is hereby amended by the addition of the words double-

underlined and the deletion of the words stricken to read as follows:

(c) The intent of the city council in establishing these procedures relating to the designation processmeans of publication is to serve the public interest in providing an accurate and reliable resource to the citizens residents and businesses of the city, to ensure that responsible and representative government is maintained on the highest order of the general good of the city. No interests are intended to vest in thefor any designated newspaper means of publication by virtue of such designation except for charges having been incurred for services provided pursuant to contract. The city council shall, in the public interest, have the right to prior terminate or suspend the designation of the designated newspaper means of publication at all times, and during such suspension or upon such termination by resolution select an interim legal newspapermeans of publication, until the suspension is removed or replacement secured pursuant to the standards of this section.

(4) Section 2-54 is hereby amended by the addition of the words double-underlined and the deletion of the words stricken to read as follows:

Sec. 2-54. - Public hearings.

City council may direct that a matter of significant interest be scheduled as a public hearing. Where the method of notice for a public hearing is not otherwise specified by law or by council action, notice shall be given by one publication, at least ten days prior to the hearing, or less than ten days for good cause shown, in by any newspaper means of publication legally qualifiedauthorized for city publications.

4

(5) Subsections 2-55(a), 2-55(b)(2) and 2-55(b)(4) are hereby amended by

the addition of the words double-underlined and the deletion of the words stricken to read as follows:

Sec. 2-55. - Adoption of codes by reference.

(a) Definitions. The following words, terms and phrases, when used in this section, shall have the meanings ascribed to them in this subsection, except where the context clearly indicates a different meaning:

Code means any published compilation of statutes, ordinances, rules, regulations

or standards adopted by the federal government or the state, or by an agency of either of them, or by any municipality within the state or by any state or nationally recognized organization, institution or agency, such as but not limited to the Pacific Coast Building Officials Conference and the National Fire Protection Association. The city council may adopt a recodification of the city's own ordinances by ordinance, which ordinance shall be published as any other is publishedby any means of publication and which ordinance need not follow the publication and hearing requirements for codes adopted by reference in the codification or recite all penalties found in the recodification.

Primary code means any code which is directly adopted by reference in whole or in part by any ordinance passed pursuant to the Charter.

Secondary code means any code which is incorporated by reference, directly or indirectly, in whole or in part, in any primary code or in any secondary code.

(b) Procedure.

(2) After the first reading of the adopting ordinance, the council shall schedule a public hearing concerning the adopting ordinance and of the code and any secondary codes to be adopted thereby. Notice of the hearing shall be published twice by any means of publication,in a newspaper meeting the requirements for publication of ordinances, once at least eight days preceding the hearing and once at least 15 days preceding it. The notice shall state the time and place of the hearing, that copies of the adopting ordinance, copies of the primary code and also copies of the secondary codes, if any, being considered for adoption are on file with the city clerk and are open to public inspection. The notice shall also contain a description which the council deems sufficient to give notice to interested persons of the purpose of the code and of any secondary code incorporated thereby by reference, the subject matter of each such code, the name and address of the agency by which each has been promulgated or, if a municipality, the corporate name of such municipality which has enacted such code and the date of publication of such code, and, in the case of a code of any municipality, the notice shall contain a

5

specific reference to the code of a given municipality as it existed and was effective at a given date.

(4) The adopting ordinance shall be posted and the title of the ordinance shall

be published by any means of publication as is provided in the case of any other ordinance. The council shall not be required to read the code text at the meetings at which the adopting ordinance is passed on first and second readings, provided that such codes and primary codes, if any, are on file in the office of the city clerk, as provided in this subsection. A supply of codes shall be maintained as follows:

(6) Subsection 2-86(d)(4) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows: Sec. 2-86. - Parks and open space advisory commission. (d) Meetings.

(4) All meetings shall be held in compliance with the city's open meeting

requirements as set forth in the City Code. In addition to the requirements set forth therein for notice of open meetings, notice shall be published at least once in by any means of publication newspaper of general circulation within the city with regard to any meeting of the parks and open space advisory commission, the purpose of which is to consider final recommendations for the parks and open space master plan or project recommendations by the parks and open space advisory commission to the city council. At the meetings, members of the public shall be allowed reasonable time to speak and present oral and/or written opinions on the plans prior to any recommendation to the city council. Where an immediate action and recommendation to the city council is necessary to acquire open space property or property rights not previously included in the parks and open space master plan, the parks and open space advisory commission may forego the requirement of noticeto publish the notice in the newspaper of general circulation.

(7) Subsection 2-237(b) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows: Sec. 2-237. - State law exclusion; precincts and polling places. (b) No election precinct or part thereof shall be located in more than one ward. Any changes to existing polling places or the addition of any new polling places shall be established by the election commission at least 30 days before any election is held. The polling places, as established, shall be posted in designated public places and printed in the city's legal newspapernotice shall be provided by any means of publication at least

6

three consecutive times before the election, except for consolidated elections conducted pursuant to the Uniform Election Code of 1992, as amended.

(8) Subsection 18-34(d)(2)(b) is hereby amended by the addition of the words double-underlined and the deletion of the words stricken to read as follows: Sec. 18-34. - Appeals to the development permits and appeals board. (d) Public notice. Notice of public hearings under this section shall be provided as

follows:

(2) Notice of the public hearing shall be provided by:

(b). Any means of Publication publication in a newspaper of general circulation in the community at least ten days prior to the public hearing; and

(9) Subsection 18-37(d) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows: Sec. 18-37. - Comprehensive Plan amendments. (d) Notice. The city shall publish notice of public hearing for a proposed major

amendment in a newspaperby any means of publication of general circulation in the community at least ten days before the hearing.

(10) Subsection 18-41(c)(1) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows: Sec. 18-41. - Zoning amendments.

(c) Council review and action. Council review and action on amendments to this chapter or zoning district changes shall be subject to the following:

(1) Before the council holds the public hearing on an amendment to this

chapter or on a request for a change in a zoning district classification or boundary, the director shall give notice of the public hearing in by a newspaperany means of publication of general circulation in the community at least ten days before the hearing.

(11) Subsection 18-43(f)(2) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows: Sec. 18-43. - Conceptual site plan review.

7

(f) Council review of a conceptual site plan. A conceptual site plan is subject to council review as follows:

(2) Before the council holds the public hearing on an application for a

conceptual site plan, the director shall give notice of the public hearing in by a newspaperany means of publication of general circulation in the community at least ten days before the hearing.

(12) Subsection 18-50(a)(2) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows: Sec. 18-50. - Major development permits.

(a) Board review of major development permit. A major development permit is subject to board review as follows:

(2) Before the board holds the public hearing on an application for a

development permit, the director shall give notice of the public hearing in by a newspaperany means of publication of general circulation in the community at least ten days before the hearing.

(13) Subsection 26-28(d) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows: Sec. 26-28. - Procedure for disposition of funds.

(d) If the depositor or owner did not receive the notice by certified mail, return receipt requested, notice shall also be published in by a newspaperany means of publication of general circulation in the city once a week for four successive weeks. The notice shall state that if the depositor or owner fails to provide the director with a written claim for the return of the unclaimed property within 30 days from the date of the last publication of the notice, the unclaimed property shall become the sole property of city, to be utilized as it deems appropriate.

(14) Section 26-178 is hereby amended by the addition of the words double-

underlined and the deletion of the words stricken to read as follows: Sec. 26-178. - Public notice.

Adequate public notice of the invitation for bids under this division shall be given a reasonable time prior to the date set forth for the opening of bids, in accordance with policies promulgated by the city manager. Such notice may include publication in by a newspaperany means of publication in of general circulation a reasonable time prior to bid opening.

8

(15) Subsection 26-399(h)(2) is hereby amended by the addition of the words double-underlined and the deletion of the words stricken to read as follows: Sec. 26-399. - Lien; assessments; collection.

(h) Methods of enforcing collection.

(2) Distraint seizure; advertisement of sale. The agent charged with the seizure shall make or cause to be made an account of the goods or effects distrained, a copy of which, signed by the agent making such distraint, shall be left with the owner or possessor or at the owner's or possessor's usual place of abode with some member of the owner's or possessor's family over the age of 18 years. The account may also be left at the owner's or possessor's usual place of business with the owner's or possessor's stenographer, bookkeeper or chief clerk or, if the taxpayer is a corporation, shall be left with any officer, manager, general agent or agent for process, with a note of the sum demanded and the time and place of sale; and shall forthwith cause to be published a notice of the time and place of sale, together with a description of the property to be sold in by a legal newspaperany means of publication within the county wherein distraint is made, or, in lieu thereof and in the discretion of the city treasurer, the agent or sheriff shall cause such notice to be publicly posted at the courthouse of the county wherein such distraint is made, and copies thereof to be posted in at least two other public places within such county. The time fixed for the sale shall not be less than ten days nor more than 60 days from the date of such notification to the owner or possessor of the property and the publication or posting of such notices. The sale may be adjourned from time to time by such agent or sheriff if it is deemed advisable, but not for a time to exceed a total of 90 days from the date first fixed for the sale. When any personal property is advertised for sale under distraint, the agent or sheriff making the seizure shall proceed to sell such property at public auction, offering the property at not less than a fair minimum price, including the expenses of making the seizure and of advertising the sale, and if the amount bid for the property at the sale is not equal to the fair minimum price so fixed, the agent or sheriff conducting the sale may declare such to be purchased by such agent or sheriff for the city. The property so purchased may be sold by the agent or the sheriff under such regulations as may be prescribed by the city treasurer. In any case of distraint for the payment of taxes, the goods, chattels or effects so distrained shall be restored to the owner or possessor if, prior to the sale, the amount due is paid, together with the fees and other charges or may be redeemed by any person holding evidence satisfactory to the city treasurer of right of possession.

(16) Subsection 38-66(2) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows:

9

Sec. 38-66. - Disposal of unclaimed or abandoned property.

(2) Any such property may be sold at public sale, provided that the

purchasing agent shall cause to be published in by the city's legal newspaperany means of publication or by auction, notice a notice setting forth a general description of the articles to be sold; the time, date and place of sale; and the time, date and place for any person who claims to be the owner of or claims any interest in any article so described to appear before the time and date set for sale to reclaim the property upon presentation of satisfactory proof of identity and ownership of such articles.

(17) Subsection 54-41(d) is hereby amended by the addition of the words

double-underlined and the deletion of the words stricken to read as follows: Sec. 54-41. - Career service pay plan.

(d) The council shall annually enact a pay plan for all positions in the career service system. The council shall conduct a public hearing before adopting the pay plan. At the hearing, any employees or agents or representatives of employees may appear in addition to any other interested parties. Prior to the hearing, each employee shall be given written notice of the hearing, which notice shall have attached to it a copy of the city manager recommended pay plan. A notice advertising the public hearing shall be published in the city's newspaperby any means of publication designated for legal publications at least ten days before the hearing and the notice shall be posted in six public places as provided for by resolution of the council.

(18) Subsection 62-31(a) is hereby amended by the addition of the words double-underlined and the deletion of the words stricken to read as follows: Sec. 62-31. - Notice of hearing on proposed district; waiver.

(a) Unless excused pursuant to subsection (c) of this section, the city clerk shall give notice of hearing for district initiation pursuant to this article, whether by petition or pursuant to the authority of the city manager. Such notice shall be published once in by a newspaperany means of publication having general circulation in the city at least 15 days prior to the date of the hearing. The city clerk shall also mail such notice by United States mail, postage prepaid, to the owners of land situated within the proposed district on or about the date of such publication; however, legal publication shall be deemed good and sufficient, and the failure of receipt of written notice shall not cause the district formation proceedings to be legally defective. Ownerships shall be deemed properly determined if taken from the records of the county assessor within 30 days prior to such mailing.

10

(19) Subsection 62-36(a) is hereby amended by the addition of the words double-underlined and the deletion of the words stricken to read as follows:

Sec. 62-36. - Notice of hearing on assessment roll; hearing.

(a) Unless excused pursuant to subsection (c) of this section, the city clerk shall give notice of hearing on the assessment roll by one publication in by a newspaperany means of publication having general circulation in the city at least 15 days prior to the date of hearing. The city clerk shall also mail such notice by United States mail, postage prepaid, to the owners of land to be assessed for the costs of improvements situated within the district on or about the date of such publication; however, legal publication shall be deemed good and sufficient, and the failure of receipt of mailed notice shall not cause the hearing on assessment roll to be legally deficient. Ownerships shall be deemed properly determined if taken from the records of the county assessor within 30 days prior to such mailing.

(20) Subsection 66-78(a) is hereby amended by the addition of the words double-underlined and the deletion of the words stricken to read as follows: Sec. 66-78. - Creation of an infrastructure reimbursement fee.

(a) Notice. The infrastructure department shall publish a notice of a proposed infrastructure reimbursement fee facility and specific geographic area within which the fee will apply in by the newspaperany means of publication so designated for public notice by the city. The notice shall provide a description of the improvements the city intends to install, an estimate of the infrastructure reimbursement fee based upon the cost estimates for the facility, and the date and time that city council will consider establishing the infrastructure reimbursement fee. A notice shall also be mailed to property owners of record located within the specific geographic area. The notice shall also state that a public hearing will not be held unless requested by a property owner. Any property that benefits from the public improvement that annexes to the city after the improvement is constructed, may be charged its proportionate share through an annexation agreement.

(21) Section 74-255 is hereby amended by the addition of the words double-underlined and the deletion of the words stricken to read as follows: Sec. 74-255. - Effective date for customers without sand/grease traps.

In order to allow adequate time for installation of sand/grease interceptors where required by Section 74-251, the installation requirements set forth in this part and the requirement for installation of sand/grease interceptors shall be fully complied with by each customers identified in Section 74-251 whose establishment is in operation but who has not constructed such facilities upon the effective date of this article within six months from the date of the customer's receipt, by certified mail or personal service, of a notice of violation issued by the public works director. The notice shall be directed to

11

the person whose name appears on the customer's utility account with the city, and receipt of the notice by such person shall constitute receipt by the customer. The public works director may reduce the six-month period for compliance for any or all such customers if the public works director determines that the reduction is necessary for the efficient operation of the sewer system and if a notice of the reduced period of compliance is published in by the legal newspaperany means of publication of the city.

(22) Subsection 74-325(b) is hereby amended by the addition of the words double-underlined and the deletion of the words stricken to read as follows: Sec. 74-325. - Compliance with pretreatment standards.

(b) The city shall annually publish in by the newspaperany means of publication with the largest daily circulation within the city a list of industrial users with wastewater contribution permits issued by the city in significant noncompliance with applicable pretreatment requirements in accordance with definitions and regulations as set forth in 40 CFR 403.8.

(23) If any portion of this ordinance is held to be unconstitutional or invalid for

any reason, such decision shall not affect the constitutionality or validity of the remaining portions of this ordinance. City Council hereby declares that it would have passed this ordinance and each part hereof irrespective of the fact that any one part be declared unconstitutional or invalid.

(24) All other ordinances or portions thereof inconsistent or conflicting with this

ordinance or any portions hereof are hereby repealed to the extent of such inconsistency or conflict.

(25) The repeal or amendment of any provision of the Code by this ordinance

shall not release, extinguish, alter, modify, or change in whole or in part any penalty, forfeiture, or liability, either civil or criminal, which shall have been incurred under such provision, and each provision shall be treated and held as still remaining in force for the purpose of sustaining any and all proper actions, suits, proceedings, and prosecutions for the enforcement of the penalty, forfeiture, or liability, as well as for the purpose of sustaining any judgment, decree, or order which can or may be rendered, entered, or made in such actions, suits, proceedings, or prosecutions.

(26) This ordinance shall take effect upon final passage.

12

INTRODUCED, READ, PASSED on first reading, ordered posted in full, and title ordered published by the City Council of the City of Thornton, Colorado, on , 2016. PASSED AND ADOPTED on second and final reading on , 2016. CITY OF THORNTON, COLORADO Heidi K. Williams, Mayor ATTEST: Nancy A. Vincent, City Clerk THIS ORDINANCE IS ON FILE IN THE CITY CLERK’S OFFICE FOR PUBLIC INSPECTION. APPROVED AS TO LEGAL FORM: Gary G. Jacobson, Interim City Attorney PUBLICATION: Posted in six (6) public places after first and second readings. Published in the Northglenn-Thornton Sentinel after first reading on , 2016, and after second and final reading on , 2016.

A

COUNCIL UPDATE COMMUNICATION PAGE 2

BACKGROUND (ANALYSIS/NEXT STEPS/HISTORY): (includes previous City Council action) Amendments to Chapter 18 The amendments to Chapter 18 establish a two option permitting process, a Development Permit or Operator Agreement. The process and requirements for the Development Permit are outlined in the draft ordinance. The process for an Operator Agreement is also outlined in the draft ordinance, while the requirements would be approved by City Council. The amendments to Chapter 18 reflect prior discussion and direction from City Council. Oil and gas developments are not restricted to specific land use zone, but the development regulations include provisions for enhanced setbacks (1,000 feet from all buildings, 750 feet from unbuilt lots or parks, and 500 feet water bodies). In addition, there are increased development standards for fencing, noise mitigation, signage, screening, landscaping, and spill and release response, among others. There are also a number of operational plans that will be required upon application and reviewed as part of the development permit process:

• Emergency Preparedness and Response Plan • Air Quality Impact Assessment and Mitigation Plan • Dust Suppression, Noise, Glare, and Light Mitigation Plan • Storm Water Control Plan • Integrity Management Plan • Water Availability Plan • Water Quality and Impact Plan • Transportation Plan Wildlife and Habitat Assessment Plan • Vegetation and Weed Management Plan • Grading, Drainage, and Erosion Control Plan • Reclamation Plan • Geologic Assessment Report • Landscape Plan

The draft ordinance also includes provisions for right of entry, inspections, and enforcement to address any ongoing concerns after the development permit is issued. Staff is also researching additional provisions to immediately suspend or revoke a permit in a situation that presents a threat to public health and safety. The provision would include options for immediate mitigation to be performed by the City if necessary at the operator’s expense. Amendments to Chapter 38 The amendments to Chapter 38 require a new oil and gas development using City streets to obtain an Access Road Permit and pay the applicable permit fee, as determined in the Access Road Impact Fee study. City Council would adopt the fee by resolution and any revenue collected by the fee would be used to offset the cost of repairing roads that were damaged by oil and gas development. The recommended onetime fees are $515 per well pad and $4,250 per well. In addition, the amendments to Chapter 38 require submission of a traffic management plan and trucking routes that must be approved by the Traffic Engineer and will take into consideration potential traffic congestion and safety concerns.

COUNCIL UPDATE COMMUNICATION PAGE 3

Public Outreach Process The recommended public outreach process would include a stakeholder meeting with three separate groups; the oil and gas industry, concerned community groups, and the development community. In addition, the draft regulations will be shared with Adams County and the Colorado Oil and Gas Conservation Commission (COGCC) for review and comment. As the oil and gas regulations apply to every property in the City, notice of the public hearing would be provided to every address in Thornton and would need to be sent out at least 30 days in advance of the public hearing. The purpose of the stakeholder meetings is to explain, answer questions, and solicit feedback on the draft regulations. The stakeholder meetings may highlight aspects of the draft regulations that could be changed in the final draft considered by City Council. Any changes in the recommended draft regulations would be presented to City Council in advance of the public hearing and all comments from the stakeholder meetings would be provided to City Council.

1

INTRODUCED BY: AN ORDINANCE AMENDING SECTIONS 18-450 AND 18-583 PERTAINING TO AMENDING ZONING DISTRICTS FOR OIL AND GAS OPERATIONS, REPEALING AND REENACTING ARTICLE X OF THE OIL AND GAS REGULATIONS, AND AMENDING SECTION 18-901 OF ARTICLE XI OF DEFINITIONS, OF CHAPTER 18 OF THE THORNTON CITY CODE.

WHEREAS, Chapter 18 of the Thornton City Code (“Code”), titled as the Development Code, is a compilation of the requirements, standards and performance expectations for land uses and land development allowed within the City of Thornton; and

WHEREAS, the intent of the Development Code is to promote the health, safety and general welfare of the public, and to implement the goals, objectives, and policies of the City’s Comprehensive Plan in accordance with the visions and desires of the community; and

WHEREAS, the current Development Code was recodified in 2011 and includes Article X, Oil and Gas Facility Regulations establishing specific regulations for Oil and Gas Operations within the City and establishing uses for such development in specified zoning districts within the City; and

WHEREAS, since the 2011 recodification of the Code, the Colorado Oil and Gas Conservation Commission (“COGCC”) formed by the Oil and Gas Conservation Act (“Act”) has promulgated updated rules (“COGCC Rules”) associated with Oil and Gas Operations; and

WHEREAS, the Colorado Department of Public Health and Environment (“CDPHE”) has updated specific regulations associated with the operation of Oil and Gas facilities; and

WHEREAS, there has been a significant increase in Oil and Gas Operations in the City necessitating updates to the City’s Oil and Gas Regulations to enhance the City’s ability to address impacts of such development; and

WHEREAS, it is the intent of the City Council to enact these Regulations consistent with the requirements of the Act and the COGCC Rules and thereby allow the responsible development of oil and gas resources in the City while protecting the public health, safety, welfare of its residents and businesses, and the environment; and

WHEREAS, it is further the City Council’s intent, by enacting these Regulations to mitigate the adverse impacts associated with Oil and Gas Operations to protect the health and wellbeing of residents pursuant to the City’s land use authority and general police powers.

2

NOW, THEREFORE, BE IT ORDAINED BY THE CITY COUNCIL OF THE CITY

OF THORNTON, COLORADO, AS FOLLOWS:

1. The introduction to Section 18-450, Development standards by zoning district chart, of the Thornton City Code is hereby amended by the addition of the words underlined to read as follows: Sec. 18-450. Development standards by zoning district chart.

In addition to the development standards for each zoning district and other relevant provisions of the Thornton City Code, every building requiring a Certificate of Occupancy issued in accordance with the City's Building Code shall be setback up to 1,000 feet from an existing Oil and Gas Operation whether such is located in the City or in an unincorporated area. This chart identifies the development standards for the listed zoning districts. Additional regulations, such as design and landscaping requirements, are referenced elsewhere in this Chapter.

2. Subsection (c) of Section 18-583, Treatment of land unsuitable for

development, of the Thornton City Code is hereby amended by the deletion of the words stricken and the addition of the words underlined to read as follows: Sec. 18-583. General requirements.

(c) Treatment of land unsuitable for development.

(2) Land unsuitable for development shall include areas:

(e) Where well sites or production sites are located or proposed to be located. The restricted lot or tract shall be of an adequate size to allow a the following minimum separation requirement: of 200 feet between the well site and any nearest existing or proposed main building. The minimum separation of 200 feet may be modified at the time of subdivision approval based on the following criteri

(1) Proposed dwelling unit density or proposed floor area ratio;

(2) Topography;

3

(3) Capability of redevelopment of the restrict lot or tract for future residential or nonresidential development in compliance with this division; and

(4) Alternative materials and methods that provide an equivalent level of safety to adjacent buildings and occupants as determined by the fire department.

1. Up to 1000 but no less than 750 feet between the well site or production site and any nearest existing building permitted for occupancy, and;

2. Up to 750 but no less than 500 feet from proposed platted residential lots or parks, sports fields and playgrounds or other designated outside activity areas; and

3. 500 feet from any surface water body, domestic or commercial water well, or irrigation well. The term “water body”, as used in this Section shall not include agricultural ditches or canals, or any type of stream or creek.

f. Where production sites are located or proposed to be located. The restricted lot or tract shall be of an adequate size to allow a minimum separation of 350 feet between the production site and any nearest existing or proposed main building. The size required for the restricted lot or tract shall be determined at the time of subdivision approval. The minimum separation of 350 feet may be modified at the time of subdivision approved based on the following criteria:

(1) Proposed dwelling unit density or proposed floor area ration;

(2) Total capacity of all production tanks;

(3) Topography;

(4) Capability of redevelopment of the restricted lot or tract for future residential or nonresidential development in compliance with this division; and

4

(5) Alternative materials and methods that provide an equivalent level of safety to adjacent buildings and occupants as determined by the fire department.

g.f. The size required for the restricted lot or tract shall be determined at the time of initial subdivision approval and the size of the lot or tract cannot be changed by subdivision amendment in a manner that obviates the separation restrictions on the lot or tract.

h.g. Where plugged and abandoned Wells are located or proposed to be located outside of right-of-way. The restricted tract shall be not less than 50 feet in width and 100 feet in length.

1. The plugged or capped and abandoned well shall be located generally in the center of the restricted tract.

2. A well maintenance and workover easement, granted to the City, shall be provided over the entire restricted tract;

3. An access easement for ingress and egress to the restricted tract of a width of not less than 20 feet shall be granted to the City unless access is available directly from the right-of-way.

4. The plugged and abandoned well shall be permanently marked by a brass plaque set in concrete similar to a permanent bench mark to monument its existence and location. The plaque shall contain any information required on a dry hole marker by the Colorado Oil and Gas Conservation Commission and the City.

3. Article X, Oil and Gas Facility Regulations of the Thornton City Code is

hereby repealed and reenacted to read as follows: ARTICLE X OIL AND GAS FACILITY REGULATIONS. DIVISION 1. GENERALLY Sec. 18-860. Purpose.

5

The City Council finds and declares that:

(a) The City, pursuant to its power to protect and promote the health, safety, environment, and general welfare of the residents and businesses of the City, is enacting and has the power to enforce regulations for oil and gas well sites, production sites, and related facilities (“Regulations”) as provided in this Article. It is the City's intent by enacting these Regulations to accommodate the development of oil and gas resources within its corporate limits while mitigating potential adverse impacts and land use conflicts between such development and existing, as well as planned, land uses.

(b) These Regulations are promulgated through the powers granted the City through the Colorado State Constitution, applicable state law, and are an exercise of the City’s land use and zoning authority and its police power.

Sec. 18-861. Applicability.

(a) New Oil and Gas Operations located wholly or partially within the City and the expansion of existing Oil and Gas Operations within the City are subject to these Regulations.

(b) Oil and Gas Operations within the City that are in existence on the

effective date of reenactment of this Article, or Oil and Gas Operations that are in existence, but located within territory which thereafter is annexed to the City are not subject to these Regulations. Provided however, when such existing Oil and Gas Operations becomes within a 1,000 foot proximity of the real property boundary line of any type of development that was not in existence when the Oil and Gas Operations were authorized, the following regulations shall apply: a Lighting Plan pursuant to 18-865(b)(6)(b) and implemented in Section 18-870, Landscaping 18-865(b)(6)(l) and implemented by 18-871, along with the Weed Management Plan in Section 18-865(g)(i), the Noise Mitigation provisions in Section 18-869, the Fencing requirement contained in Section 18-873, Signage in Section 18-874, and Access Road provisions in Section 18-885, these Regulations shall apply.

(c) A Development Permit issued pursuant to these Regulations shall

authorize the Operator, its agents, employees, subcontractors, and independent contractors, to perform the work reasonably necessary to conduct the activities specified by the Development Permit, subject to all other applicable City regulations or the Code. The right to

6

conduct an Oil and Gas Operation terminates if the operation of the well site or production site is discontinued for a period of six months or more, other than by temporary abandonment or shut-in which is in conformance with COGCC Rules. Renewing operations on a site after the six-month period shall require a new Development Permit.

(d) Any renovation or repair of accessory equipment or pumping systems

associated with an Oil and Gas Operation in existence on the effective date of these Regulations shall be permitted without a Development Permit, provided the work does not increase the degree of nonconformity or impact of the Oil and Gas Operation. Any replacement of existing accessory equipment or any addition of accessory equipment shall conform to these Regulations and require a Minor Development Permit, pursuant to Section 18-49. The replacement or addition of individual tanks, treaters, or separators shall not require the remaining accessory equipment in a production site, an access road, or a well site, to conform to the Development Standards in these Regulations.

(e) An Operator Agreement approved by the City may, by its terms,

exempt the proposed Oil and Gas Operation from these Regulations. (f) Oil and Gas Operations to be located on any type of City-owned

property are exempt from these Regulations; provided however, all such Oil and Gas Operations shall be required to enter into an Operator Agreement to obtain a Development Permit.

(g) Nothing in these Regulations shall be construed to limit other

applicable provisions of the Code not in conflict with these Regulations. If there is a conflict between these Regulations and other regulations and standards in this Chapter, these Regulations shall govern. Any references to days, within which any action is required to occur, such reference shall mean calendar days, unless otherwise specifically stated.

Secs. 18-862-18-863. Reserved. DIVISION 2. DEVELOPMENT PERMIT Sec. 18-864. Development Permit Required.

(a) It shall be unlawful for any person to commence an Oil and Gas Operation unless a Development Permit has first been granted by the City in accordance with the Development Permit procedures in this

7

Article and Sections 18-48 and 18-50 of the Code, or an Operator Agreement pursuant to Section 18-896.

(b) A Development Permit for Oil and Gas Operations may be granted on

property that has not been subdivided without requiring the property to be subdivided.

(c) Operators are required to obtain a City Sales and Use tax license by

filing the appropriate application with the Finance Director. (d) Operators shall obtain all building and other applicable permits and

licenses prior to the construction of all above-ground structures or facilities as required by the City Building Code.

(e) Notice procedures:

(1) Every Operator of any Oil and Gas Operation subject to these Regulations shall designate an agent residing within the state to receive any legal process or orders and notices provided for in this Article. Notice of change of the agent and the agent's address shall be submitted by certified mail, return receipt requested, to the LGD within 10 days following the occurrence of such change.

(2) Notice to the LGD shall be effective upon receipt by the

department at the following address: City of Thornton, 9500 Civic Center Drive, Thornton, CO 80229; Attention City Development.

(f) Notice for consideration of a Development Permit reviewed by the

Board shall be in accordance with Section 18-50. Sec. 18-865. Application Requirements for Development Permits for Oil and Gas Operations.

Section 18-865 applies to all applications for Development Permits for Oil and Gas Operations.

The Director or Designee may waive one or more of the application requirements if they are not applicable given the nature or location of the Oil and Gas Operation. The Director or Designee may also request from the applicant additional information deemed necessary for the review of the Development Permit application to evaluate compliance with these Regulations.

8

(a) An application for a Development Permit shall be submitted with full payment of the applicable application fee, as set forth by resolution of the Thornton City Council. The applicant shall also be responsible for all other costs associated with review, processing and approval of the application in accordance with applicable provisions of the Code. All such costs or any additional permit fees shall be paid prior to issuance of a Development Permit.

(b) An application for a Development Permit shall be submitted to the

Director or Designee and shall include the following materials:

(1) The application shall be on a form furnished by the City and is in addition to that required by Section 18-31 and must include the Operator’s name and address and, if any type of entity, the name and address of the registered agent of the Operator; or any other person that the Operator designates to receive notice.

(2) A summary operational statement for the proposed Oil and

Gas Operations including anticipated number of wells upon full build-out, proposed on-site storage, any proposed phasing of the development, and anticipated operational hours on-site and for seismic and drilling operations.

(3) Copies of applicable COGCC Forms 1, 2, and 2A. (4) A listing of all permits or approvals obtained or yet to be

obtained from state or federal agencies other than COGCC. (5) A copy of an applicable overweight or oversized truck permit

and an Access Road Permit issued to the Operator by the City's Traffic Engineer.

(6) The following types of plans or reports shall be provided with

the application. To avoid duplicative or unnecessary work, the Operator may submit any plans or reports prepared for the COGCC or other regulatory agencies that the Director or Designee determines are adequate substitutes for the plans and reports required in this Section.

(a) Air Quality Impact Assessment and Mitigation Plan.

The plan shall demonstrate the means of compliance with the Colorado Air Quality Control Commission ("CAQCC") and a means to minimize VOC emissions,

9

compliance with all applicable federal EPA Regulations, an assessment of air quality impacts of the proposed Oil and Gas Operation, and a plan to mitigate impacts and maintain air quality in compliance with these Regulations.

(b) Lighting Plan. A photometric study and plan for

installation of lighting that mitigates light pollution and spill-over onto properties within 100 feet of the pad site; provided, however, that the Operator may still use lighting that is necessary for public and occupational safety.

(c) Noise Management Plan. A plan identifying hours of

maximum noise emissions, type, frequency, level of noise to be emitted. The plan shall include proposed mitigation measures and a requirement that all decibel readings to verify compliance with these Regulations shall be taken from the setback line for each well and production site.

(d) Stormwater Control Plan. A copy of the stormwater

management plan submitted to the Water Quality Control Division and a description of the procedures to comply with the applicable COGCC stormwater control requirements in Rule 1002(f).

(e) Gathering Pipeline Integrity Management Plan.

1. Operator of a gas gathering pipeline shall prepare and maintain an integrity management plan in conformance with 49 CFR § 192, Subpart O.

2. Operator of an oil gathering pipeline shall

prepare and maintain an integrity management plan in conformance with 49 CFR § 195.452.

3. The plan shall include location of existing

pipelines and existing and proposed gathering pipeline(s) identify the material, thickness, diameter and operating pressure of existing and proposed pipelines; identify the materials transported in existing pipeline(s); identify the

10

easement(s) by location and dimension; and identify owner of each existing pipeline.

(f) Water Availability Plan. The plan shall identify the

anticipated volume of water needed for each phase of the operation and verification of all sources of water for the life of the proposed operation. The plan shall recognize and take into consideration that the City will not allow city water to be used by the Oil and Gas Operator.

(g) Water Quality Impact Assessment and Monitoring Plan.

The plan shall establish a baseline and a process for monitoring changes to water quality and the aquatic environment to demonstrate the effectiveness of mitigation. The plan shall include an inventory and location of all water bodies and groundwater, as well as domestic and commercial water wells within one mile of the proposed development. At a minimum, the plan shall address: 1. Key stream segments, other water bodies, and

groundwater to be monitored. 2. Locations for and frequency of sampling and

monitoring to establish baseline of existing conditions prior to the proposed Oil and Gas Operation including existing water quality, aquatic life and macro-invertebrates, and groundwater data.

3. Key indicators of water quality and stream

health, and threshold levels that will be monitored to detect changes in the water quality and health of the aquatic environment.

4. Locations for and frequency of sampling and

monitoring for key indicators of water quality and stream health, including but not limited to, constituents regulated by the COGCC, and constituents associated with the proposed Oil and Gas Operation.

11

5. Locations for frequency of sampling and monitoring to measure effectiveness of water quality mitigation during the life of the proposed Oil and Gas Operation and five years after final reclamation of all disturbed areas are complete.

6. Projected impacts to water quality and mitigation

steps that will be implemented to avoid degradation of water bodies if monitoring of key indicators reveals degradation.

(h) Wildlife and Habitat Assessment Mitigation Plan. The

plan shall include identification of existing wildlife and wildlife habitat, as defined by the Colorado Division of Parks and Wildlife, an evaluation of the impacts of the proposed Oil and Gas Operations on wildlife and wildlife habitat, and proposed mitigation measures.

(i) Vegetation, Weed Management and Reclamation Plan.

The plan shall include a written description of the species, character and density of existing vegetation on the site, a summary of the potential impacts to vegetation as a result of the proposed Oil and Gas Operations, and proposed mitigation to address these impacts and to comply with Section 38-444 of the Code. The plan shall also include an interim and final reclamation plan in conformance with COGCC reclamation requirements.

(j) Grading, Drainage and Erosion Control Plan. The plan

shall identify existing and proposed contours, at two foot intervals, and the methods for controlling erosion and dust suppression during construction and for all phases of the proposed Oil and Gas Operation.

(k) Geological Assessment Report. This report shall detail

the geological characteristics of the site prepared by a registered engineer; at no cost to the City. The report shall include an assessment of the geologic hazards within one mile of the site and the plan for mitigating impacts from geologic hazards to the proposed development and impacts of the proposed development on such geologic hazards.

12

(l) Landscape Plan. The landscape plan shall explain how the Oil and Gas Operations will be constructed in a manner that will minimize the removal of and damage to existing trees and vegetation. 1. The plan shall include placement of earthen

berms around the perimeter fencing, when feasible, and is in addition to applicable ground cover.

2. The plan must account for proper irrigation of

plant materials, except, automatic irrigation systems are not required.

(m) Vicinity Map that includes:

1. The location of all existing bodies of water and

watercourses, including direction of water flow. This information shall be submitted on United States Geological Service ("USGS") 7.5 minute series, assessor base maps which indicate topographic detail and show all existing bodies of water and watercourses with a physically defined channel within a 1,000 foot radius of the proposed well or a map of equal quality and information.

2. The location of existing oil and gas wells as

reflected in COGCC records including abandoned wells, within a 1,000 foot radius of the proposed location for the well.

3. The location of proposed well site and proposed

production site, including the information submitted on COGCC Form 2, and shall be graphically depicted on a map of the section in which the sites are to be located. The information shall also include the parcel tax identification number of the property on which the well site and production site is to be located.

(n) Facilities Plan that includes:

13

1. A depiction of all proposed well sites, production sites and associated facilities of the Oil and Gas Operation submitted on one or more plats or maps no less than one inch equals 100 feet or larger, showing:

2. A legal description of the property upon which all

facilities associated with the Oil and Gas Operation are proposed to be situated.

3. A north arrow and proper identification of the

proposed well and shall depict the location of the proposed well site, production site including any well, proposed twinning locations, motors, tank battery, separators and treaters, production pits, transmission and gathering pipelines, and other accessory equipment to be used during the drilling, maintenance and operation of the Oil and Gas Operation. The Operating Plan shall identify all proposed accessways, and storage facilities associated with the well site and production site depicted, and shall contain a description and location of proposed landscaping, intended color of paint for storage tanks and other permanent structures, fencing and berming for the site.

4. A depiction all existing physical features,

including drainageways, floodplains, roads and rights-of-way within 1,000 feet of a well site or production site. The Operating Plan shall also depict existing subdivision boundaries, existing buildings or structures, property lines, public and private utility easements of record and utility facilities and improvements on or located within 1,000 feet of the well site or production site.

5. A topographic map and aerial photo of the site

and a boundary map specifically identifying the boundary lines for the development site facilities.

6. The location of existing and proposed

transmission lines and gathering pipeline(s) identified by material, thickness, diameter and

14

operating pressure and the easement identified by location and dimension.

7. The location of guy line anchors buried for future

use. 8. A map of all locations of existing oil and gas

wells or injection wells as reflected in the COGCC records.

(o) Emergency Preparedness and Response Plan. A plan

for each specific facility associated with the proposed Oil and Gas Operation in compliance with the International Fire Code as amended in the Code. The plan shall be filed with the Thornton Fire Department and the City’s Emergency Manager and updated on an annual basis or as conditions change (responsible field personnel change, ownership changes, etc.). The plan shall consist of at least the following information: 1. Name, address and phone number, including 24

hour emergency numbers for at least two persons responsible for emergency field operations.

2. A facilities map depicting the proposed locations

and type of above and below ground facilities including sizes, and depths below grade of all oil and gas gathering and transmission lines and associated equipment, isolation valves, surface operations and their functions, as well as transportation routes to and from exploration and development sites, for emergency response and management purposes.

3. Detailed information addressing each reasonable

potential emergency that may be associated with the operation. This may include any or all of the following: explosions, fires, gas, oil or water pipeline leaks or ruptures, hydrogen sulfide or other toxic gas emissions, or hazardous material vehicle accidents or spills.

15

4. A provision that any spill outside of the containment area, that has the potential to leave the facility or to threaten waters of the state, or as required by the plan approved by the City shall be reported to the local emergency dispatch and the COGCC Director in accordance with COGCC Rules.

5. Detailed information identifying access or

evacuation routes, and health care facilities anticipated to be used.

6. A project specific emergency preparedness plan

for any project that involves drilling or penetrating through known zones of hydrogen sulfide gas.

7. Detailed information showing that the Operator

has adequate personnel, supplies, and training to implement the plan immediately at all times during construction and operations.

8. An Operator shall have current Material Safety

Data Sheets ("MSDS") for all chemicals used or stored on a site. The MSDS sheets shall be provided immediately and at any stage of development upon request by city officials, a public safety officer, or a health professional.

9. A community outreach policy that establishes a

process by which the Operator engages with the surrounding neighbors to educate them on the risks of the on-site operations and to establish a process for surrounding neighbors to communicate with the Operator. The policy shall include training by the Operator and employees associated with the plan shall be coordinated with the Director or Designee and Emergency Manager.

10. The Operator will provide the Director or

Designee names and contact information for a third party emergency response agency, other than the Thornton Fire Department, an

16

independent contractor, or a division within the Operator’s Oil and Gas Operation that is appropriately equipped to respond to the specific emergency and other hazardous incidents that may occur in connection with the operation and proof that such agency or independent contractor is willing and able to respond to any such incident occurring on the site of the operation.

11. The Plan shall acknowledge that if an

emergency situation arises at the Oil and Gas Operation that creates an imminent threat to health and safety as determined by the City, the Operator will, at the request of the City, immediately cease all operations until the Operator advises the City that the emergency is abated.

12. A provision obligating the Operator to reimburse

the appropriate emergency response service providers for costs incurred in connection with any emergency in accordance with Colorado State Statutes.

(p) Transportation Plan.

1. The Operator shall prepare a comprehensive transportation plan that includes a detailed description of all proposed private and public access and haul routes for all product produced and transported, equipment delivered, removed water, sand, waste solids, fluids, E&P Waste, and any other materials to be hauled onto or from the development site.

2. The plan shall include a description of vehicles;

including the license plate number of each vehicle, a description of each vehicle type, including the weight of each vehicle unloaded and loaded and the number of wheels and axles for each vehicle. The plan shall also include an estimate of the number of trips per day for each type of vehicle and for each phase of the Oil and

17

Gas Operation. The foregoing information shall also be separately provided to the Traffic Engineer in connection with the process requiring the Operator to obtain an Access Road Permit.

3. The plan shall include a means to insure that the

use of public roads and public intersections will be in a manner that minimizes delay in use of public roads by the general public. The Operator will coordinate with the City’s Traffic Engineer to achieve this result.

(q) Chemicals and Hydraulic Fracturing Fluids Disposal

and Reporting Plan. A plan for disposal and reporting of chemicals and hydraulic fracturing fluids.

(r) Spill Prevention Control and Countermeasures Plan.

The plan shall provide, at a minimum, for the following: 1. Operator shall investigate, contain, and clean-up

spill release immediately. All employees shall be qualified for clean-up of spills in accordance with applicable federal and state requirements.

2. Report COGCC Rule 906 spills and releases to the Director or Designee within 10 days after discovery and to enhance discovery adopt an electronic monitoring program.

3. Spills and releases which exceed one barrel of

E&P Waste or produced fluids shall be reported to the Director or Designee within 24 hours.

4. Spills and releases that impact or threaten to

impact waters of the state, residence or occupied structure, livestock or public byway shall be reported verbally to the Director or Designee within 24 hours.

5. Spills and releases that impact or threaten to

impact water supply area shall be reported verbally to Colorado Environmental Spill

18

Reporting Hotline and the Director or Designee immediately after discovery.

6. Spills and releases that impact or threaten to

impact a water supply intake shall be reported immediately to the Director or Designee and if the City is not the owner, also to the owner of the facility.

7. Chemical spills and releases shall be reported in

compliance with state and federal laws. 8. Uncontrolled events shall be reported to the

Director or Designee within 24 hours following the incident. Spill Report Form 19 and Form 23 Well Control Reports shall be submitted to the Director or Designee at the same time that they are submitted to the COGCC pursuant to COGCC Rule 327. The Operator shall provide an emergency phone number for reporting spills to the City.

Sec. 18-866. Conditions of Development Permits for Oil and Gas Operations.

All Oil and Gas Operations shall comply with the Development Standards set forth in Division 3 of this Article, which Standards shall be terms and conditions of a Development Permit Approval by the Board. In addition, the Director or Designee shall not issue a Development Permit authorized by the Board until the Director or Designee has received from the Operator verification that any additional conditions that were imposed by the Board have been met. DIVISION 3. DEVELOPMENT STANDARDS Unless a Development Standard is waived pursuant to 18-895, the proposed Oil and Gas Operations wholly or partially within the City limits must demonstrate compliance with each of these Development Standards before the Board will issue a Development Permit. Sec. 18-867. Setbacks.

All Oil and Gas Operation facilities or structures (above-ground) shall be setback in accordance with the following provision. Setback measurements shall be from the boundary line specified by the Operator in the Operating Plan submitted and the edge or corner of the nearest building or the nearest boundary of an outdoor activity area, a property line, or a street or roadway:

19

(a) Oil and Gas Operations shall be setback 1,000 feet from occupied

buildings or buildings permitted for construction and shown on the applicable plat or applicable construction plans identifying the location of such buildings.

(b) Oil and Gas Operations shall be setback 750 feet from platted

residential lots or the boundary line for designated parks, sports fields and/ playground areas, designated open space or other designated outside activity areas.

(c) Oil and Gas Operations other than pipelines shall be setback 500 feet

from any surface water body, domestic or commercial water wells, or irrigation wells. The term "Water body," as used in this Section, shall not include agricultural ditches or canals, or any type of stream or creek.

(d) Oil and Gas Operations shall be setback 500 feet from any property

line. Sec. 18-868. Surface disturbance.

The Oil and Gas Operation shall be located and constructed in a manner that eliminates unnecessary or excessive site disturbance and that minimizes the amount of cut and fill on-site:

(a) Multi-well drill pads shall be used for multiple wells and operations shall be consolidated whenever possible.

(b) The size of the structure and surface equipment for present and

future operational needs shall be minimized. (c) Pad dimensions shall be reduced to a size necessary to

accommodate operations, and will be located in a manner to minimize impacts on surrounding uses and be compatible with the natural topography and existing vegetation.

Sec. 18-869. Noise.

(a) Noise levels shall conform to COGCC noise regulations except that the noise level in any zone district at any time of day shall not exceed 60 db(A). No measurements shall be taken when traffic is passing the sound level meter.

20

(b) Operations shall comply with the Noise Management Plan. (c) Electric motors and rigs shall be used where use of electric power is

practicable. Sec. 18-870. Lighting.

All lighting shall be installed in compliance with the Lighting Plan. Sec. 18-871. Landscaping and Reclamation.

(a) The Operator shall implement the Landscape Plan and the Vegetation, Weed Management, and Reclamation Plan.

(b) Unless otherwise required by the Landscape Plan, the edges of the cleared vegetation shall be feathered and thinned and the vegetation should be mowed, or brushed-hogged, while leaving root structure intact, instead of scraping the surface. All plant materials used shall be maintained in healthy going condition at all times. The Operator is responsible for the regular weeding, mowing, fertilizer, pruning and other maintenance of all plant materials as needed.

(c) After commencement of production operations all excavation slopes,

both cut and filled, shall be planted and maintained with grasses, plants, or shrubs for the purpose of adequate erosion control.

Sec. 18-872. Containment Berms.

(a) Containment berm or other secondary containment facilities shall be installed around crude oil, condensate, and produced water storage tanks capable of impounding 150% of the capacity of the largest tank size within the berm.

(b) Containment berms shall be constructed of steel rings or equivalent

technology. (c) A maximum two crude oil or condensate storage tanks shall be

located within a single berm. (d) Secondary containment areas for tanks shall be constructed with a

synthetic or engineered liner, mechanically connected to the ring. (e) No potential ignition sources shall be located inside secondary

containment area unless the area encloses a fired vessel.

21

(f) Electrical lines shall be installed underground. (g) Operator shall remove and dispose of all construction-related debris

upon commencement of Operations and keep site free of debris and excess materials.

(h) Operator shall remove all equipment used for drilling, re-completion

and maintenance within 30 days after work is completed. Sec. 18-873. Fencing.

(a) All pumping systems and accessory equipment shall be screened on all sides by a non-flammable privacy fence of a height equal to the highest accessory equipment.

(b) Chain link, wrought iron or other type of open style fence material

shall be installed surrounding the entire site. (c) Access shall be provided by a securely locked, solid gate that

preserves the integrity of the screening but that is designed to allow access by emergency responders.

(d) Operator shall use the factory applied finish or may paint wrought iron

black; galvanized is appropriate for chain link fence. Sec. 18-874. Signs.

Operator shall install signs with Operator contact and well information and warning of safety hazards. All Oil and Gas Operations shall be posted within a "No Trespassing" sign, which may be incorporated into any warning sign. Sec. 18-875. Floodplain.

(a) Oil and Gas Operations shall be designed and operated in compliance with City floodplain regulations.

(b) The equipment and facilities of an Oil and Gas Operation shall be

anchored to resist flotation, collapse, lateral movements, or subsidence.

Sec. 18-876. Well Leak Detection and Repair. Operator shall implement the Leak Detection and Repair Plan.

22

Sec. 18-877. Water Reuse/Waste Water.

(a) Operator shall recycle and reuse water and minimize waste water production.

(b) No E&P Waste shall be permanently stored on the site. E&P Waste

shall be stored in tanks on-site for no longer than three months and transported off-site by tanker trucks for disposal at facilities approved to receive E&P Waste.

Sec. 18-878. Water Quality/Supply.

(a) The Operator has demonstrated an adequate water supply is available for all phases of the Oil and Gas Operation.

(b) The Oil and Gas Operation shall not cause significant degradation of water quality of affected water bodies as set forth in the approved Water Quality Impact Assessment and Monitoring Plan. (1) Maintenance of machinery is prohibited within 300 feet of

water body; a water body shall not include an agricultural ditch, streams or creeks.

(2) No fluids shall be discharged off site, except pursuant to an

approved discharge permit.

(3) Operator shall test for metals and other pollutants to establish baseline and post drilling in accordance with the approved Water Quality Assessment and Monitoring Plan.

(4) Closed loop systems are required.

(5) Underground injection wells are prohibited within the City.

Sec. 18-879. Air Quality Standards.

(a) Produced gas shall be captured unless release is required for safety purposes; uncontrolled venting is prohibited.

(b) Where electric engines are not possible, fossil fueled engines shall

employ the latest emission-reduction technologies.

23

(c) Operator shall submit a compliance plan to the Director or Designee for all instances of non-compliance with Air Pollution Control Division Regulation 7 in the annual certification report.

(d) Flaring is prohibited except under upset or emergency conditions. (e) Automated well control measures shall be installed to prevent gas

venting during emission control system failures or other upset conditions.

Sec. 18-880. Green Completions - Emission Control Systems.

Flow lines, separators, and sand traps shall be consistent with the green completion requirements of COGCC Rule 805. Sec. 18-881. Chemical Disclosure and Hazardous Material Storage.

(a) Chemical disclosure shall be made in compliance with COGCC Rules.

(b) Hazardous material storage shall be conducted in compliance with the Chemicals and Hydraulic Fluids Disposal and Reporting Plan.

Sec. 18-882. Spill and Release, Response, and Reporting.

Spill and release response and reporting shall be in compliance with the Spill Prevention Control and Countermeasures Plan. Sec. 18-883. Discharge Values.

(a) Discharge valves shall be secured. (b) Open-ended discharge valves shall be placed in containment.

Sec. 18-884. Traffic.

Operator shall implement the Transportation Plan. Sec. 18-885. Access Roads.

(a) Access roads to a production site: (1) Shall be a graded roadway having a prepared subgrade and

an aggregate base course surface a minimum of 10 inches

24

thick compacted to a minimum density of 95% of the maximum density determined in accordance with generally accepted engineering sampling and testing procedures.

(2) The aggregate base course at a minimum shall meet the

requirements for the State Department of Highways' Class 1, 4, 5, or 6 aggregate base courses as specified in the State Department of Highways' Standard Specifications for Road and Bridge Construction, latest edition.

(3) The access road shall be graded so as to provide drainage

from the roadway surface and constructed to allow for cross drainage of waterways (i.e., roadside swales, gulches, rivers, creeks, etc.) by means of an adequate culvert pipe. Adequacy of the pipe shall be subject to approval of the development engineering manager.

(b) Access roads to a well site:

(1) Shall be graded, dirt roadway compacted to a minimum

density of 95% of the maximum density determined in accordance with generally accepted engineering sampling and testing procedures.

(2) Graded so as to provide drainage from the roadway surface

and constructed to allow for cross drainage of waterways by means of an adequate culvert pipe. Adequacy of the pipe shall be subject to approval of the development engineering manager.

(c) All proposed access roads to well sites and production sites which gain access off of a paved public right-of-way shall be improved as stated in this Section and, in addition, the point of intersection with the public right-of-way shall be improved to the following minimum standards: (1) An access width of 20 feet with paved 35 foot radii at each

side of the access road at the point of intersection with the public right-of-way;

(2) A minimum of six inches of asphalt pavement over the initial

20 foot portion of the proposed access road, beginning at the edge of the existing pavement of a paved public right-of-way; the Operator shall maintain the private access portion of this

25

road. In addition, two inches minimum for gravel shoulders on either side of the asphalt pavement;

(3) The road shall be improved from the point of connection a

minimum of distance of 200 feet on the access road; (4) Traction chains from heavy equipment shall be removed

before entering public roadways; and (5) The Operator shall take all practicable measures to ensure

that vehicles do not track mud or debris onto public roads. If mud or debris is nonetheless deposited on a public road, the Operator shall, within a reasonable time, clean the road; this obligation is in addition to general maintenance obligations below.

(d) General maintenance obligations to clean road shall include use of a

street sweeper to clean public access roads from all dust, mud, or debris daily or more frequently as deemed necessary by the City. All such street cleaning shall be to the satisfaction of the City. Snow removal shall be on the private portion of the access roads referenced in Subsection (c)(3) above and shall occur within 24 hours of storms which produced accumulations of snow of two inches depth or greater. The Operator shall keep all private roads and access road in good repair at all times such that the roads continue to meet the road standards set forth herein.

Sec. 18-886. Wildlife Standards.

(a) The Oil and Gas Operation shall not cause significant degradation of wildlife or wildlife habitat and the Operator shall implement the Wildlife and Habitat Assessment and Mitigation Plan.

(b) When a well site or production site is located in a significant wildlife habitat, as defined by the Colorado Division of Parks and Wildlife, or where designated in the City's Comprehensive Plan, the applicant shall consult with the Colorado Division of Parks and Wildlife and the City shall obtain recommendations for appropriate site-specific impact mitigation procedures. The Operator shall implement such procedures as recommended by the Colorado Division of Parks and Wildlife in addition to any other requirements set forth in in the Wildlife and Habitat Assessment and Mitigation Plan.

Sec. 18-887. Load Lines.

26

Load lines shall be capped, bullplugged or locked shut. Load line receivers/valves

shall be placed inside secondary containment areas or in a proper load line containment device or both. Sec. 18-888. Compatibility with Surrounding Uses.

(a) Site Preferences.

(1) Production and storage facilities shall be located away from prominent natural features such as distinctive rock and land formations, vegetative patterns, river or creek crossings, City-owned and designated open space areas, and other designated landmarks. Such sites shall be located to avoid the top of hills and ridges in order to prevent the appearance of pumpjack and accessory equipment profiles on the horizon.

(2) Facilities shall be located at the base of slopes to provide a

background of topography and/or natural cover whenever geology and soil conditions allow. The applicant shall align on-site roads to follow existing grades and minimize cuts and fills.

(b) Facilities Mitigation.

(1) Facilities shall be painted as follows:

(a) Uniform, non-contrasting, non-reflective color tones, similar to the Munsell soil color coding system.

(b) The color of facilities shall be matched to land, not the

sky, and be slightly darker than adjacent landscape. (c) Any exposed concrete shall be colored to match the soil

color. (2) Electric pumping systems shall be required in all areas where

service is technically and practicably available. Electrical lines servicing pumping and accessory equipment shall be installed below ground.

(3) All structures and equipment shall be regularly maintained so

as not to become so deteriorated as to be hazardous or potentially injurious to the public health and safety.

27

(4) Landscaping for the site shall be installed in accordance with

the Landscaping Plan approved when a Development Permit is granted. Maintenance of the Landscaping Plan as approved is required on and surrounding the site in accordance with the applicable provision of Chapter 18 of the Code at all times the site is owned by the Operator.

(5) When an Oil and Gas Operation becomes operational, all

construction-related debris shall be removed from the site for proper disposal. The entire site shall be maintained free of debris and excess materials at all times during operations. Burying debris or any type of excess materials on-site is prohibited.

(6) All equipment used for drilling, re-completion and maintenance

of the facility shall be removed from the site within 30 days of completion of the work. Permanent storage of equipment on well pad sites shall not be allowed.

Sec. 18-889. Blowout Preventer Equipment.

(a) Blowout Preventer Equipment for Drilling Operations. (1) Rig with Kelly Drive; double ram with blind ram and pipe ram;

annular preventer or a rotating head. (2) Rig without Kelly Drive; double ram with blind ram and pipe

ram. (3) Pressure test casing string and each component of blowout

prevention equipment upon initial rig-up and minimum once every 30 days during drilling operations; document and retain results up to one year.

(4) Daily activation of pipe rams for function testing. (5) Mineral management certification or approved training

required for at least one person at well site during drilling operations.

(b) Blowout Preventer Equipment for Well Servicing Operations.

28

(1) Adequate blowout prevention equipment used on all well servicing operations.

(2) Backup stabbing valves required on well servicing operations

during reverse circulation and valves pressure tested before each well servicing.

Sec. 18-890. Control of Fire Hazards.

(a) Fire hazard removed a minimum of 25 feet from the wellhead, tanks and separator.

(b) Electrical equipment installations inside the bermed area comply with

API RP 500 classifications and the National Electrical Code. Sec. 18-891. 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 feet in height and not greater than one foot east of the guy line anchor. Sec. 18-892. Tank Specifications.

The Operator shall maintain written records verifying proper design, construction, and maintenance. All newly installed or replaced crude oil and condensate storage tanks shall be designed, constructed, and maintained in accordance with the National Fire Protection Association ("NFPA") Code 30 (2008 version). All tanks that are part of the production site, and not temporary tanks, shall be no higher than nine feet. Sec. 18-893. Liability Insurance.

All Operators shall maintain general liability insurance coverage for property damage and bodily injury to third parties in the minimum amount of $2,000,000 per occurrence. Such policies shall endorse the City as an additional insured and the Operator shall provide a copy of such policy upon request by the City. In addition, the Operator shall indemnify the City for any damage or injury resulting from any Oil and Gas Operation or any hazardous or dangerous condition resulting from such operations. Sec. 18-894. Additional Standards for Gathering Pipelines.

(a) Underground Location. All gathering pipelines shall be located underground.

29

(b) Alignment. Gathering pipelines shall be aligned with established roads and share existing pipeline rights-of-way or consolidate new corridors for pipeline rights-of-way whenever possible.

(c) Water Body Crossing. Operator shall use boring technology for

gathering pipelines crossing streams, rivers or irrigation ditches.

(d) Compliance with Floodplain Regulations. Gathering pipelines located in or crossing area of special flood hazard, determined pursuant to Section 18-620, shall comply with the requirements of the City's floodplain regulations in Chapter 18, Article V, Division 7.

(e) Operators and maintenance. Operations and maintenance shall be

conducted in accordance with the Procedural Manual for operations, maintenance, and emergencies prepared in conformance with 40 CFR § 192.605 for gas gathering pipelines or 40 CFR § 195.402 for oil gathering pipelines. This manual will be provided to the Director or Designee before initial operations commence.

(f) GPS Information and As-Built Drawings. Within 30 days of

completing construction, Operator shall provide the following information to the Director or Designee:

(1) Global positioning system ("GPS") information sufficient to

locate the gathering pipeline in a format compatible with the City's GIS system.

(2) As-built drawings. (3) Engineering plans, drawings, and maps with summarized

specifications showing the horizontal location, covering depths, and location of shutoff valves of the gathering pipeline. The drawings shall show the location of other pipelines and utilities that are crossed or paralleled within 15 feet of the gathering pipeline right-of-way.

(4) Detailed cross-section drawings for all public rights-of-ways

and easement crossings on City property. (5) A list of names and mailing addresses of all residents,

property owners, and tenants adjacent to the gathering pipeline construction.

(g) Recordation of As-Built Location and Abandonment.

30

(1) Within 30 days after construction is completed, Operator shall

record a legal description of the gathering pipeline location with the City and the County Clerk and Recorder.

(2) Within 30 days after abandonment, Operator shall notify the

Director or Designee and the County Clerk and Recorder of abandonment of any recorded gathering pipeline.

(h) Restoration of Site upon Completion of Construction. Within 30 days

after construction of a gathering pipeline is completed, Operator shall grade, level, and restore the affected property to the same surface condition, as nearly as practicable, as existed before construction activities were first commenced.

(i) Valves. Gathering pipeline shall be equipped with automatic shut-off

valves or remote control valves. (j) Computerized Monitoring and Leak Detection. Gathering pipelines

shall be equipped with computerized monitoring and leak detection that provides immediate notice of any leak to the City's emergency response providers.

(k) Oil Gathering Pipelines. In addition to the provisions of 40 CFR §

195 and the above standards, these additional requirements apply to oil gathering pipelines:

(1) Setback. Oil gathering pipelines shall be located at a

minimum distance of 500 feet from a residence, school, or place of business.

(2) Periodic Reports and Reporting of Accidents and Safety

Related Conditions for Oil Gathering Pipelines.

(a) Operator shall provide the Director or Designee with copies of the periodic reports at the time of reporting to the Pipeline Hazardous Materials Safety Administration ("PHMSA").

(b) Operator shall notify the Director or Designee of

accidents and safety related conditions at the time of reporting to the PHMSA.

(c) Flowlines are to be inspected daily.

31

(l) Gas Gathering Pipelines. In addition to the provisions of 40 CFR §

192 and the above standards, these additional requirements apply to gas gathering pipelines.

(1) Notification of Gas Leaks. Operator shall notify the Director or

Designee immediately of gas leaks that would result in evacuation of any people or road or railroad closures.

(2) Standards for Gas Gathering Pipelines located in areas with

10 or fewer buildings or outdoor areas of public assembly within 220 yards on either side of the centerline of any continuous one mile length of pipeline.

(a) Hoop stress of 20% or more MAOP or more than 125

psig. Metallic gathering pipelines with a MAOP that produces a hoop stress of 20% or more of the SMYS or non-metallic gathering pipelines with a MAOP of more than 125 psig, shall comply with the transmission line requirements of 49 CFR § 192, except for Subpart D.

(b) Hoop stress of less than 20% MAOP or less than 125

psig. Metallic gathering pipelines with a MAOP that produces a hoop stress of 20% or less of the SMYS or non-metallic gathering pipelines with a MAOP of less than 125 psig shall comply with the following:

1. If a line is new, replaced, relocated or otherwise

changed, the design, installation, construction, initial inspection, and initial testing must comply with the following:

i. Design and Installation:

a. § 192 Subpart B. b. § 192 Subpart C. c. § 192 Subpart D.

ii. Construction and Inspection: § 192

Subpart B. iii. Initial Testing: § 192 Subpart J.

32

2. Metallic gathering pipelines shall comply with corrosion control requirements of 49 CFR § 192.614, Subpart L.

3. Operator shall carry out a damage prevention

program described in 49 CFR § 192.614, Subpart L.

4. Operator shall establish a public education

program as required by 49 CFR § 192.616, Subpart L.

5. Operator shall install and maintain line markers

required by 49 CFR § 192.707, Subpart M. 6. Operator shall carry out a leakage control

program according to 49 CFR § 192.723(b), Subpart M.

7. Operator shall prepare a Procedural Manual

addressing the maintenance and operational requirements of this Section.

8. Flowlines are to be inspected daily.

Sec. 18-895. Waiver of Development Standards.

An applicant may request waiver of one or more of the Development Standards in this Division 3 because of operational conflict, because of technical infeasibility, or for environmental protection purposes.

(a) Operational Conflict. A Development Standard may be waived by the City Council, if compliance with the Development Standard would materially impede or destroy the state's interest in the responsible, balanced development, production and utilization of oil and gas consistent with protection of public health, safety and welfare, including protection of the environment and wildlife resources.

(1) Waiver Request. Upon written request by the applicant, a

public hearing before the City Council will be scheduled to take place as soon as possible following receipt of the written waiver request.

(2) Notice of Public Hearing.

33

(a) The notice of public hearing on the waiver request shall

be prepared by the Director or Designee and shall include a description of the proposed Oil and Gas Operation standard(s) sought to be waived, and the date and location of the hearing.

(b) Not less than 15 calendar days prior to the hearing, the

Director or Designee shall publish the notice of the public hearing on the waiver request using any authorized means of publication at the City's expense.

(c) Not less than 15 calendar days prior to the date of the

public hearing on the waiver request, the Director or Designee shall mail written notice of the public hearing to owners of real property within one-half mile of the subject parcel where the proposed Oil and Gas Operations are located. The list of property owners to be notified shall be compiled by the Director or Designee using the most current list of property owners on file with the County Assessor. The applicant shall be responsible for reimbursing the City for all costs associated with the notice of hearing.

(3) Decision by City Council. The City Council may waive the

standard if it is determined that based on evidence and testimony at the hearing, that compliance with the Development Standard will create an operational conflict as described in Subsection (a). The City Council may impose conditions that are necessary to minimize any negative impacts of the waiver.

(b) Technical Infeasibility. A Development Standard may be waived by

the City Council, based upon technical infeasibility asserted by the applicant at any time during the application review process and prior to the final decision on the application. The City Council may approve the request for waiver if it is determined that there is no economical technology commercially available to conduct the proposed Oil and Gas Operation in compliance with the standard and conduct of the proposed Oil and Gas Operation, if the standard is waived, will be protective of public health, safety, welfare, the environment, and wildlife resources.

34

(1) Waiver Request. Upon written request by the applicant, a public hearing before the City Council will be scheduled to take place as soon as possible following receipt of the written waiver request.

(2) Notice of Public Hearing.

(a) The notice of public hearing on the waiver request shall be prepared by the Director or Designee and shall include a description of the proposed Oil and Gas Operation, description of the standard(s) sought to be waived, and the date and location of the hearing.

(b) Not less than 15 calendar days prior to the hearing, the Director or Designee shall publish the notice of the public hearing on the waiver request using any authorized means of publication at the City's expense.

(c) Not less than 15 calendar days prior to the date of the

public hearing on the wavier request, the Director or Designee shall mail written notice of the public hearing to owners of real property within one-half mile of the subject parcel where the proposed Oil and Gas Operations are located. The list of property owners to be notified shall be compiled by the Director or Designee using the most current list of property owners on file with the County Assessor. The applicant shall be responsible for reimbursing the City for all costs associated with the notice of hearing.

(3) Decision by City Council. The City Council may waive the

standard if it determines that based on evidence and testimony at the hearing, that compliance with the Development Standard is technically infeasible as described in Subsection (b) herein. The City Council may impose conditions that are necessary to minimize any negative impacts of the waiver.

(c) Environmental Protection. The Operator may make a written request

to the Director or Designee for a waiver based on environmental protection at any time during the application review process prior to the final decision on the application. The Director or Designee may approve the request for waiver if protection of public health, safety, welfare and the environment will be enhanced by an alternate approach not contemplated by the standard.

35

Sec. 18-896. Operator Agreement.

In lieu of submitting an application for a Development Permit pursuant to these Regulations an Operator may seek permission from the City to enter into negotiations for an Operator Agreement between the City and the Operator for development of Oil and Gas Operations, to be approved by the City Council, and upon terms and conditions that shall be mutually beneficial and shall meet or exceed the requirements of these Regulations.

(a) An Operator wishing to enter into an Operator Agreement with the City must submit a written request to the Director or Designee.

(1) A form Operator Agreement, in a form approved by the

Director or Designee, is available upon request; but is not required.

(2) The minimum submittal requirements of Section 18-865(a) and

(b)(1) through (5) shall be required. (3) Termination of an Operator Agreement by an Operator without

a cessation of production requires the Operator to obtain a Development Permit pursuant to Section 18-864, prior to termination of the Operator's Agreement.

(b) Upon approval of an Operator Agreement, as to form and terms, the

Operator Agreement shall be presented to the City Council for administrative approval at a regular meeting.

(c) In addition to notice by means of publication and posting, the notice of the City Council hearing shall be mailed to property owners within one-half mile of the outer boundary of the proposed Operation.

(d) Approval of the Operating Agreement will authorize issuance of a Development Permit to the applicant.

DIVISION 4. ENFORCEMENT Sec. 18-897. Enforcement Remedies.

Notwithstanding applicable provisions Section 18-4 of the Code, all enforcement remedies are cumulative. Sec. 18-898. Right to Enter/Inspections.

36

The City shall have a right to inspect all Oil and Gas Operations upon reasonable

notice. By accepting an approved Development Permit or Operator's Agreement, the applicant grants consent to such inspections.

(a) Right to Enter. For the purpose of implementing and enforcing these Regulations duly authorized City personnel or contractors may enter onto the Operator's Property upon a minimum three days' notice to the Operator or any other party holding a legal interest in the Property.

(b) Operator contract. The applicant shall provide the telephone number of a contact person who may be reached 24 hours a day for purposes of being notified of any proposed City inspection under this Section. Permitted Oil and Gas Operations may be inspected by the City at any time to ensure compliance with the requirements of the approved Development Permit, provided that a minimum of 72 hours' notice is given to the contact person at the telephone number or email address supplied by the applicant.

(c) The cost of any City inspection deemed reasonable and necessary to

implement or enforce these Regulations shall be borne by the applicant, provided such inspections and fees are not in conflict with COGCC inspections and rules.

(d) If entry is denied, the City shall have the authority to discontinue

application processing, or initiate the process to revoke a Development Permit pursuant to Section 18-899, or to obtain an order from a court of competent jurisdiction to obtain entry.

Sec. 18-899. Revocation of a Development Permit.

The following provisions supersede Section 18-4(b) of the Code:

(a) If the City Manager believes an Operator has failed to conduct its Oil and Gas Operations in accordance with the terms and conditions of the approved Permit and these Regulations, the City Manager may initiate proceedings herein to revoke or suspend the Operator's Development Permit.

(1) As a condition precedent to initiating a proceeding to revoke a

Development Permit, the City must provide written notice to Operator specifying, in reasonable detail, the factual basis to assert the failure of the Operator to comply with the

37

Development Permit requirements and the remedy required. The Operator shall have 10 calendar days from the date of the receipt of the notice to commence actions to remedy the failure and such actions shall be completed within a reasonable time.

(2) If the Operator fails to remedy a failure in the manner set forth

above, the City Manager shall request a hearing before the City Council. Upon 10 days written notice sent by certified mail to the Operator, the City Council shall schedule a public hearing on the alleged failure of the Operator to comply with the requirements of the Operator's Development Permit and these Regulations. At such hearing, the City Council may determine that no such failure occurred, that such failure occurred but was remedied in the manner set forth above, or that such failure occurred and has not been remedied.

(b) If the City Council finds that the Operator has failed to comply with

the Development Permit requirements or these Regulations, and such failure has not been remedied, the City Council, upon a 15 day notice to Operator prior to such action, may act in its discretion to suspend or revoke the Development Permit and any or all approvals for operations of the subject Oil and Gas Operations.

(c) Upon such revocation, Operator shall cease the Oil and Gas

Operation at issue until it obtains approval for such Operation under the then-applicable City Code. If the Operator fails to comply, the City may initiate a legal proceeding to enforce the City Council's Order.

4. Section 18-901 is hereby amended by the addition of the words double-

underlined and the deletion of the words stricken, and all other Definitions remained unchanged, to read as follows:

Sec. 18-901. Definitions.

The following words, terms and phrases, when used in this chapter, shall have the meanings ascribed to them in this section, except where the context clearly indicates a different meaning:

Closed loop systems means a closed loop mud drilling system that typically

consists of steel tanks for mud and storage, and the use of solids removal equipment, which normally includes some combination of shale shakers, mud cleaners and centrifuges sitting on top of the mud tanks. This equipment separates drill cutting solids

38

from the mud stream coming out of the wellbore while retaining the water or fluid portion to be reused in the continued drilling of the well bore. The solids are placed in containment provided on the site. The system differs from conventional drilling where a reserve pit is used to allow gravitational setting of the solids from the mud which can then be reused. A closed loop system does not include use of a conventional reserve drilling pit.

COGCC means the Colorado Oil and Gas Conservation Commission of the State

of Colorado. Completion means the process that perforates well casing, stimulates the reservoir

using various techniques, including but not limited, to acid treatment and Hydraulic Fracturing, allows for the flowback of petroleum or natural gas from wells to expel drilling and reservoir fluids, and tests the reservoir flow characteristics, which may vent produced hydrocarbons to the atmosphere via an open pit or tank.

Expansion of oil and gas operations means an increase in the size of a drilling pad

or an increase in the number of wells at an existing Oil and Gas Operation. Exploration and Production Waste ("E&P Wastes") means those wastes

associated with operations to locate or remove oil or gas from the ground or to remove impurities from such substances and which are uniquely associated with and intrinsic to oil and gas exploration, development, or production operations that are exempt from regulation under Subtitle C of the Resource Conservation and Recovery Act (RCRA), 42 USC Sections 6921, et seq. For natural gas, primary field operations include those production-related activities at or near the well head and at the gas plant (regardless of whether or not the gas plant is at or near the wellhead) but prior to transport of the natural gas from the gas plant to the market. In addition, uniquely associated wastes derived from the production stream along the gas plant feeder pipelines are considered E&P Wastes, even if a change of custody in the natural gas has occurred between the wellhead and the gas plant. In addition, wastes uniquely associated with the operations to recover natural gas from underground storage fields are considered to be E&P Wastes.

Flowline means a pipeline connecting individual well sites to gathering lines. Gathering pipeline means a pipeline that transports gas or oil from a current

production facility to a transmission line or main. Geologic hazard means a geologic condition which is adverse to current or

foreseeable future construction or land use associated therewith constituting a hazard to public health and safety or property. This includes but is not limited to landslide, rock fall, slope failure, mudflow or other unstable surface or subsurface conditions and includes subsurface features such as fault lines, aquifers and other geothermic and geologic phenomena.

39

Green completion practices mean those practices intended to reduce emissions of

salable gas and condensate vapors during cleanout and flowback operations prior to the well being placed in production and as thereafter applicable.

Hydraulic Fracturing or Hydraulic Fracturing Treatment means all stages of the

treatment of a well by the application of Hydraulic Fracturing Fluid under pressure that is expressly designed to initiate or propagate fractures in a target geologic formation to enhance production of oil and natural gas.

Hydraulic Fracturing Fluid means the fluid, including the applicable base fluid and

all Hydraulic Fracturing additives, used to perform a Hydraulic Fracturing Treatment. Injection well means any hole drilled into the earth into which fluids are injected for

the purposes of secondary recovery, storage, or disposal, pursuant to authorizations granted by the COGCC.

Kelly Drive means a type of well drilling device on an oil and gas drilling rig that

uses a section of pipe that digs the well deeper. Load Line means a type of hose to pump oil and water into a transport truck. Local government designee [LGD] means the person designated by the City

Manager, who receives on behalf of the City copies of all documents required or requested to be filed with the local government designee pursuant to the COGCC regulations and these rules.

Maximum allowable operation pressure [MAOP] means the maximum pressure at

which a pipeline or segment of a pipeline may be operated pursuant to 49 Code of Federal Regulations 192 Part A.

Oil and Gas Containment Berm means a barrier of any type used for preventing

the passage of liquid materials or providing screening from adjacent uses as may be specified in an applicable development standard.

Oil and Gas Operations means the exploration for oil and gas; the siting, drilling,

deepening, recompletion, reworking, refracturing, closure or abandonment of a Well and pumping stations, the Production site for oil and gas production, including required facilities and operations, accessory equipment, construction, site preparation, reclamation and any and all related activities associated with the development of oil and gas resources.

40

Operator means the person designated as operator and named in COGCC form 2 or a subsequently filed COGCC form 10 and exercises the right to control the conduct of Oil and Gas Operations.

Operator Agreement means an agreement between the City and an Operator

describing how proposed Oil and Gas Operations are to be conducted within the municipal boundaries.

Pitless means with respect to drilling, there is no pit regardless of size or function.

This includes conventional reserve drilling pits and drilling cutting pits, but does not include flare pits which may be utilized to contain necessary flaring during the drilling, completion, or up-set conditions. An above ground water tight metal or other material container is utilized instead of a sub-surface pit to hold drilling cuttings until they are disposed of.

Production site means that surface area immediately surrounding proposed or

existing production pits, or other accessory equipment and facilities that are necessary for oil and gas production operations, exclusive of transmission and gathering pipelines.

Production Facility means any storage, separation, treating, dehydration, artificial

lift, power supply, compression, pumping, metering, monitoring, flowline, and other equipment directly associated with oil wells, gas wells, or injection wells.

Reclamation means the process of returning or restoring the surface of disturbed

land as nearly as practicable to its condition prior to the commencement of Oil and Gas Operations or to landowner specifications with an approved variance under COGCC Rule 502.b.

Recompletion of a well means actions taken following the initial completion of a

well, including the action and techniques of reentering the well and redoing or repairing the original completed well to restore the well’s productivity.

Specified minimum yield strength [SMYS] means:

(1) For steel pipe manufactured in accordance with a listed specification, the yield strength specified as a minimum in that specification; or

(2) For steel pipe manufactured in accordance with an unknown or unlisted specification, the yield strength determined in accordance with § 192.107(b) of 49 Code of Federal Regulations 192 Part A.

Spill means any unauthorized sudden discharge of E&P Waste to the environment.

41

Twinning means the drilling of a well adjacent to or near an existing well bore when the existing well cannot be drilled to the objective depth or produced due to an engineering problem such as collapsed casing or formation damage.

VOC Emissions means volatile organic compounds in Oil and Gas Operations that are released into the atmosphere or ground.

Well means an oil or gas well or injection well; a hole drilled for the purpose of producing oil or gas, a well into which fluids are injected, a stratigraphic well, a gas storage well, or a well-used for the purpose of monitoring or observing a reservoir.

Wildlife Habitat means a natural or man-made environment that contains the elements of food, shelter, water, and space in a combination and quantity necessary to sustain one or more wildlife or plant species at stable population levels in historically-used habitats. Sensitive wildlife habitat areas include, but are not limited to, nesting, brood rearing areas, rookeries, leaks, migration corridors, calving and fawning grounds for big game.

5. If any portion of this ordinance is held to be unconstitutional or invalid for any reason, such decision shall not affect the constitutionality or validity of the remaining portions of this ordinance. City Council hereby declares that it would have passed this ordinance and each part hereof irrespective of the fact that any one part be declared unconstitutional or invalid.

6. All other ordinances or portions thereof inconsistent or conflicting with this

ordinance or any portions hereof are hereby repealed to the extent of such inconsistency or conflict.

7. The repeal or amendment of any provision of the Code by this ordinance shall not release, extinguish, alter, modify, or change in whole or in part any penalty, forfeiture, or liability, either civil or criminal, which shall have been incurred under such provision, and each provision shall be treated and held as still remaining in force for the purpose of sustaining any and all proper actions, suits, proceedings, and prosecutions for the enforcement of the penalty, forfeiture, or liability, as well as for the purpose of sustaining any judgment, decree, or order which can or may be rendered, entered, or made in such actions, suits, proceedings, or prosecutions.

8. This ordinance shall take effect upon final passage.

INTRODUCED, READ, PASSED on first reading, ordered posted in full, and title ordered published by the City Council of the City of Thornton, Colorado, on _________________________, 2016. PASSED AND ADOPTED on second and final reading on , 2016. CITY OF THORNTON, COLORADO

42

Heidi K. Williams, Mayor ATTEST: Nancy A. Vincent, City Clerk THIS ORDINANCE IS ON FILE IN THE CITY CLERK’S OFFICE FOR PUBLIC INSPECTION. APPROVED AS TO LEGAL FORM: Gary G. Jacobson, Interim City Attorney

43

PUBLICATION: Posted in six public places after first and second readings. Published in the Northglenn Thornton Sentinel after first reading on , 2016, and after second and final reading on , 2016.

INTRODUCED BY: AN ORDINANCE AMENDING SECTION 38-523 OF THE LOCAL AMENDMENTS TO THE 2010 EDITION OF THE MODEL TRAFFIC CODE FOR COLORADO MUNICIPALITIES PERTAINING TO THE RESPONSIBILITIES OF THE OFFICE OF THE TRAFFIC ENGINEER. WHEREAS, the City has adopted local amendments to the 2010 Edition of the Model Traffic Code for Colorado Municipalities ("MTC") in Section 38-523 of the Code; and WHEREAS, such local amendments created the office of the Traffic Engineer in Section 113 of the MTC and established the duties and responsibilities for the Traffic Engineer in Section 113.5 of the MTC; and WHEREAS, the Thornton City Code (“Code”) regulates oil and gas facilities operating within the City in Chapter 18 of the Code and Section 18-879 requires that access roads used by oil and gas companies operating within the City shall obtain overweight/oversized truck permits, issued by the Traffic Engineer, for using public streets and roadways for such companies transportation needs; and WHEREAS, use of such public streets and roadways as access roads for oil and gas operations within the City or operations outside the City that similarly need to use access roads for their operations adversely impacts the useful life of these public streets and roadways, significantly impacts traffic patterns by the volume of oil and gas facility truck traffic, and consequently regulatory efforts to manage traffic flow on public streets and roadways; and WHEREAS, in 2008, Rio Blanco County, Colorado, funded a traffic study addressing the roadway impacts caused by new development, including oil and gas development activity, in the County, and the ability to create a mechanism by which those new developments could be required to pay their fair share of improvements by way of a road impact fee, and the study concluded that the increased traffic impacts related to the increase in oil and gas development generated a need for increased capacity of roads, road improvements, and consequently that the imposition of an impact fee on all oil and gas development to pay for such traffic improvements and street maintenance was a legitimate means to recoup government expenses associated with such development; and WHEREAS, the County of Boulder similarly funded an oil and gas road impact study in 2013 to understand the potential impacts of oil and gas development and production on the County’s roadways and to design a road deterioration safety fee to offset costs associated with the oil and gas truck traffic, and concluded that oil and gas roadway impact fees were inappropriate means to recoup the expenses incurred by the County associated with the effect and adverse traffic impact created by such

2

development, and thereafter developed a system for imposing and collecting transportation impact fees for all oil and gas facilities operating in the county; and WHEREAS, the Colorado Oil and Gas Task Force Final Report, set forth in Recommendation #37, recognized that “There is uniform agreement that one of the most serious impacts of oil and gas activity involves the use of large trucks and trailers.” The report recommended that the issue was serious enough to merit “special attention, study and action” such as the Rio Blanco County and Boulder County impact fees studies; and WHEREAS, the City is experiencing an increase in oil and gas facility development within the City and in the surrounding counties, and the applicable taxes and other revenue sources generated from oil and gas developments for governmental services do not generate sufficient funds to provide the necessary transportation, capital facilities, and safety improvements to accommodate and address the added impacts of oil and gas development on transportation system management and facilities within the City; and WHEREAS, without a mechanism requiring oil and gas development to a pay reasonable, fair and equitable share of the costs incurred by the City, to address capital improvements necessary as a result of the increased impacts on the City’s transportation system by use of all types of truck traffic generated by new oil and gas development in the City, such transportation system will degrade causing it to become inefficient, inconvenient, and less safe; and WHEREAS, City taxpayers will bear the costs, both financial and related to the safety of the streets and roadways impacted by such oil and gas development within the City and surrounding areas by having to delay or postpone current or future capital investments elsewhere in the City's transportation system in order to address public street and roadway impacts associated with the new oil and gas development in and surrounding the City; and WHEREAS, oil and gas development should pay its reasonable fair and equitable share of the costs associated with ensuring the public roads are kept and maintained in a safe condition and properly regulated for all types of traffic flow to enhance public safety; and WHEREAS, Colorado law recognizes the authority of local governments to impose fees to defray the expenses associated with the provision of governmental services and to anticipated future demand for such services; and WHEREAS, the office of the Traffic Engineer was established to deal with oversized and overweight truck permits and now the Traffic Engineer’s authority needs to be amended to authorize and direct the Traffic Engineer to require and issue access road permits for oil and gas development within the City; and

3

WHEREAS, the Traffic Engineer's authority ought to include the development of impact fees associated with oil and gas development, both within and without the City that use public streets and roadways, to recoup expenses related to the consequential deterioration of the streets, safety of deteriorated streets, and traffic management of streets to ensure that as oil and gas development increases, the City has the funds to address the direct impacts of such development; and WHEREAS, authorizing the Traffic Engineer to establish by Resolution approved by the City Council, a set of impact fees rationally associated with the necessity for street maintenance and to timely and properly safety concerns, as traffic regulations are a fair and equitable mechanism for allocating to new developments their fair share of the costs of maintaining and improving the capital streets and roadways within the City that are directly related to the increased oil and gas development. NOW, THEREFORE, BE IT ORDAINED BY THE CITY COUNCIL OF THE CITY OF THORNTON, COLORADO, AS FOLLOWS: 1. Section 38-523, Local Amendments to the Model Traffic Code, Section 113 is

hereby amended by addition of the words double-underlined and the deletion of the words stricken to read as follows:

Sec. 523-113. Office of the Traffic Engineer.

(1) The office of the Traffic Engineer is hereby established. The Traffic Engineer shall have the authority to exercise the powers and duties provided in this Code, and as may be referenced in the Thornton Municipal Code. Such authority shall specifically include the power to issue all types of permits or authorizations associated with the use of public streets and roadways in connection with any type of oil and gas operations impacting such public streets and roadways and to establish and impose applicable fees for such use of public streets and roadways pursuant to applicable provisions of this Code and the Thornton Municipal Code.

2. Section 38-523 Local Amendments to the Model Traffic Code, Section 113.5 is hereby amended by enactment of a new subsection 113.5(5) with the present subsection (5) and the current subsections (6), (7) and (8) renumbered accordingly, to read as follows:

113.5. Duties and Powers of Traffic Engineer or other designated traffic official.

(5) The Traffic Engineer, or designee, shall also have the authority to and responsibility for establishing standards and procedures for the issuance of any type of access road permits and to impose applicable fees related to the use of and impact on the City's public streets and roadways by motor vehicles, all types of trucks, and truck trailers in connection with the development, construction, operation, and maintenance of oil and gas

4

facilities, whether such facilities are within the City or are outside the city but intend to use or have used City streets and roadways in connection with the above described oil and gas operations. The Traffic Engineer shall also have the authority and responsibility to establish the amount of any applicable impact fees associated with the application and issuance of any permits allowing the use of public streets or roadways as such fees shall be set forth in and approved by resolution of the Thornton City Council.

a. Permit requirements. Any type of oil and gas development

operation, whether located within the City or located outside the City limits, which intends to use the public streets and roadways within the City, in any way and in connection with said oil and gas development, shall be required to obtain, in addition to any other applicable license or permit of general applicability, an Access Road Permit (“Permit”) upon application to the Traffic Engineer. The following documents and information shall accompany all Permit applications, which application form shall be established by the Traffic Engineer:

(1) Payment of the applicable Permit fee in an amount as established

by resolution of the Thornton City Council;

(2) A copy of the complete Colorado Oil and Gas Conservation Commission (herein after "COGCC") application, Form 2 or 2A, and any accompanying exhibits.

(3) A copy of the approved COGCC Permit.

(4) A Site Plan for the development describing all the facilities that are to be placed on the site initially and as anticipated for full build out, which plan shall include a topographic map identifying the location of all facilities, including but not limited to, well sites, pad sites, all types of tanks, gathering stations, and pipeline locations and easements acquired for such pipelines.

(5) A traffic management plan identifying the projected number of all types of vehicles that will be used in connection with the operations, anticipated frequency of use for the various types of vehicles; excluding personal vehicles of employees and guests.

(6) Route preferences, which shall be specific as to preferred routes,

including estimated time of day for travel and projected volume of traffic for all types of traffic. Such route preferences must be approved for all types of motor vehicles, with the exception of personal vehicles of employees or guests, which are used in the

5

development, construction, operation, and maintenance of the oil and gas development operations.

(7) No Permit shall be issued until a complete application is received,

completeness to be determined by the Traffic Engineer.

(8) No oil and gas operation Development Permit will be approved until a Permit, as required by this Section 113.5, has been issued.

(b) Impact Fees established: An Access Road Impact Fee (“Impact Fee”) is hereby authorized to be imposed by the Traffic Engineer that is intended to recoup expenses associated with the operation of oil and gas facilities in the City and for those facilities that use public streets and roadways. Impact Fees shall be imposed and collected by the Traffic Engineer in an amount as approved by the City Council by resolution.

(c) Methodology for determination of applicable Impact Fees: In

evaluating an appropriate Impact Fee, the Traffic Engineer shall consider the following factors:

(1) The recommendations contained in the Thornton Oil and Gas

Impact Fee Study conducted by BCC Research and Consulting.

(2) Traffic safety management modifications that may be necessary with respect to the routes proposed relative to the operational needs of vehicular traffic as set forth in the applicant’s Permit, to include:

(a) City Street or roadways designations relative to the composition of such streets or roadways designated in the route preferences and the corresponding degradation of such street and roadways requiring enhanced maintenance and the need to upgrade for multi-modal safety concerns as a result of the proposed routes for vehicular traffic as set forth in the applicant’s Permit;

(b) The anticipated volume of all categories of traffic both initially and at build out for such traffic necessitated by the oil and gas operation as more particularly described in the applicant’s Permit; and

(c) Types of vehicles, including specifically the identification of

the number of single axle and multi-axle vehicles used for all aspects of the oil and gas operation, and use of any of the vehicles as particularly identified in the applicant’s Permit.

6

(d) Based upon the above factors, the Impact Fee is authorized

to be imposed in the following manner: 1. A one time Impact Fee shall be calculated based upon

the following:

(a) For each and every type of well located within the permitted Oil and Gas Operation site; from the time the well is approved until the well is capped; and

(b) For each well pad; upon development approval of a production site.

(c) The amount of the Impact Fee will be established

by resolution of the Thornton City Council. 2. The Impact Fee shall be applicable for all oil and gas

developments approved by the City or that begin operations after the date of enactment of this ordinance.

3. It shall be unlawful to allow or permit a vehicle of any type associated with oil and gas development operations to use the public street or roadway within the City without first obtaining a Permit and remitting to the City all applicable Impact Fees.

3. If any portion of this ordinance is held to be unconstitutional or invalid for any

reason, such decision shall not affect the constitutionality or validity of the remaining portions of this ordinance. City Council hereby declares that it would have passed this ordinance and each part hereof irrespective of the fact that any one part be declared unconstitutional or invalid.

4. All other ordinances or portions thereof inconsistent or conflicting with this

ordinance or any portions hereof are hereby repealed to the extent of such inconsistency or conflict.

5. The repeal or amendment of any provision of the Code by this ordinance s hall

not release, extinguish, alter, modify, or change in whole or in part any penalty, forfeiture, or liability, either civil or criminal, which shall have been incurred under such provision, and each provision shall be treated and held as still remaining in force for the purpose of sustaining any and all proper actions, suits, proceedings, and prosecutions for the enforcement of the penalty, forfeiture, or liability, as well as for the purpose of sustaining any judgment, decree, or order which can or may

7

be rendered, entered, or made in such actions, suits, proceedings, or prosecutions.

6. This ordinance shall take effect upon final passage. INTRODUCED, READ, PASSED on first reading, ordered posted in full, and title ordered published by the City Council of the City of Thornton, Colorado, on , 2016. PASSED AND ADOPTED on second and final reading on , 2016. CITY OF THORNTON, COLORADO Heidi K. Williams, Mayor ATTEST: Nancy A. Vincent, City Clerk THIS ORDINANCE IS ON FILE IN THE CITY CLERK’S OFFICE FOR PUBLIC INSPECTION. APPROVED AS TO LEGAL FORM: Gary G. Jacobson, Interim City Attorney PUBLICATION: Posted in six (6) public places after first and second readings. Published in the Northglenn-Thornton Sentinel after first reading on , 2016, and after second and final reading on , 2016.

s:\legal\cityatty\ordinance\38-523-13 & 113.5 traffic permit and impact fee ordinance.doc

B

COUNCIL UPDATE COMMUNICATION PAGE 2

location or intensity, rather it was intended to provide City officials with information about the potential impacts to the transportation system, and associated costs based on the best available data. This study includes the design and calculation of a roadway impact fee that could offset the transportation‐related damage of oil and gas development. This fee was determined to be $4,250 per well, in 2016 dollars.

Page 1

EXECUTIVE SUMMARY The City of Thornton lies near Colorado’s largest oil and gas producing area the Denver-Julesburg Basin. Oil and gas development activity around Thornton has increased in recent years and has the potential to continue in the future.

Truck traffic associated with oil and gas drilling and production can significantly impact local road systems. The City of Thornton has commissioned this study to quantify the impacts of oil and gas development on the City’s roadway system. The study also includes the design and calculation of roadway impact fees that could offset the transportation-related damage of oil and gas development.

Resource Development There are five stages in the development and operation of an oil or gas well: Leasing and exploration, Pad construction, Drilling, Completion, and Production. The heaviest truck traffic and roadway impacts occur during pad construction, drilling, and completion. For a single well, these phases combine for about one month of heavy truck traffic on a typical pad site.

Nearly all pad sites within the study area (I-25 on the west, US 85 on the east, 120th Avenue on the south, and Weld County Road 6 on the north) have multiple wells. The number of wells per pad in the Niobrara has increased significantly in recent years, from around 5 in 2014, to almost 15 in 2016. On average, each pad site is expected to have about 12 wells based on observed development patterns. Given this typical configuration, the maximum development capacity within the 65 square mile study area is 195 pads, or 2,340 wells.

Since 2010, the industry has made a major shift away from vertical and directional well drilling; beginning in 2013 there have been no new vertical or directional wells drilled in the study area, only horizontal wells. The average well borehole length for horizontal wells in the study area has increased significantly in recent years, requiring additional truck trips for the water and materials needed for drilling and fracking wells with longer laterals.

Thornton Oil and Gas Development Scenarios Because of the uncertainties associated with oil and gas development in and around Thornton, this study considers three potential development scenarios in order to provide a range of potential roadway impact costs. In order to derive these hypothetical development scenarios, the study team reviewed information from multiple sources, including Colorado Oil and Gas Conservation Commission (COGCC) data on historical well drilling activity and field spacing patterns, and the current geographic distribution of oil and gas development. Based on the historic rates of development activity in the study area, the study team developed three hypothetical oil and gas development scenarios, illustrated in the table to the right. Each hypothetical scenario was then combined with a random pad site selection process in order to account for uncertainty in

Thornton Oil and Gas 10-Year Development Scenarios Category Scenario A Scenario B Scenario C Maximum wells per year 36 24 6

Maximum pads per year 3 2 1

Years of development 10 10 10

Wells at end of analysis period 324 204 54

Page 2

future oil and gas development patterns, the broader industry and economy, the sensitivity of the model to development site locations, and the relatively small study area.

Trip Generation Oil and gas development requires the transport of heavy equipment to the well site to build access roads, construct a well pad, and transport a drilling rig. Heavy trucks are also required to bring fresh water to the well site, and often to transport produced water and extracted resources off site.

The study team conducted a literature review and held conversations with Thornton and COGCC staff to understand the unique transportation needs of oil and gas development. Based on these findings, a typical horizontally-drilled and fracked well in the study area will generate an estimated 2,871 trips during its one-month development period, largely related to water delivery and removal. Once a well is in the production phase, it generates about two trips per day for the remainder of its productive life.

The study team then adapted these trip generation estimates from a one-rig, one-well format to the more common 12-well pad configuration seen in the Thornton area. This shift in development patterns and intensity affects traffic generation and the traffic profile associated with drilling activity. A typical 12-well pad will generate nearly 23,000 truck trips during the development phase.

Truck Loads For each truck, the weight and how it is distributed across a truck‘s axles are the main determinants of impacts to roadway surfaces. In addition to vehicle trips, the study team used equivalent single-axle loads (ESALs) for each trip to calculate heavy vehicle trips’ impacts on a road’s surface condition.

A variety of the vehicle types used for oil and gas activities are specialized and/or of significant weight, resulting in ESAL factors greater than many typical vehicles. The load impact of oil and gas trucks can be as much as 22,500 to 46,000 times that of a passenger car.

Oil & Gas Travel Model The study team developed a travel model using the VISUM software to assign trips and vehicle-loads (ESALs) associated with the three development scenarios to the roadway system in Thornton and surrounding areas. Although the travel model includes roadways outside of Thornton, the transportation impacts are assessed only on City roads.

The industry trips were converted into vehicle miles traveled (VMT) to compare the increase in VMT caused by oil and gas operations with existing VMT on Thornton roads. Although the number of trips generated by the oil and gas industry in the three scenarios is relatively small compared to the existing traffic, the primary transportation impact associated with industry is due to the weight of the vehicles.

Transportation Impacts and Costs Road mitigation measures and costs are defined for the roads impacted by oil and gas traffic in each of the hypothetical scenarios. Estimates of rehabilitation needs imposed by oil and gas traffic for gravel, asphalt, and concrete roads were each analyzed separately. The analysis serves to isolate the incremental impacts (and the associated mitigation costs) of the oil and gas truck activity on the road system, as follows:

• Asphalt roads – Depth of pavement overlay required to offset industry impacts

Page 3

• Concrete roads – Incremental reduction in service life and expedited reconstruction • Gravel roads – Increased frequency of grading, gravel application, and dust suppression

The annual roadway impact costs vary significantly depending on the development scenario and analysis year. This variation occurs because each scenario has a different level of development occurring, and because the randomized pad selection process yields locations both within and outside of the City. Locations in the City would generate significantly more impacts on City roads, while locations outside the City limits might only use a few segments of Thornton’s roadway system, or none at all.

The study team also examined oil and gas impacts on roadway capacity, finding that oil and gas has little or no impact on Thornton’s roadway network capacity. An analysis of oil and gas impacts on roadway safety also finds that oil and gas has no significant effect on bicycle level of service. Rarely, roads near schools may be used by the industry, and may benefit from additional crossing improvements.

Thornton Oil and Gas Roadway Impact Fee The purpose of this study is to design a fee to recover the incremental costs associated with oil and gas development on Thornton’s road network. The oil and gas road impact fees are designed to isolate the oil and gas damage on the City roads, and recoup the associated cost. They are intended to be integrated into the oil and gas land use application process in the City’s newly adopted regulations.

The oil and gas roadway impact fees are calculated by estimating the total annual roadway impact costs associated with oil and gas development and production, and then dividing the total cost by the total number of active pads and wells at the end of the ten-year analysis period. The table to the right provides the oil and gas impact fee schedule corresponding to the estimated impact cost for each new pad and new well.

The results of this study suggest a fully cost recovery fee of $515 per new pad, and $4,250 per new well. Under this fee schedule, the City could impose a total of $51,515 in roadway impact fees for a typical new 12-well pad.

The City may also allow oil and gas companies to provide evidence that their roadway impact is less than the fees derived above. In this case, the companies may perform their own traffic study to quantify the expected roadway impacts in terms of ESALs. If the City agrees to the independent traffic study results, they may impose a fee of $1.17 per ESAL lane-mile. This fee is calculated using the ESALs generated by a 12-well pad.

Thornton Oil and Gas Roadway Impact Fee Schedule (2016$) Roadway Impact Fee Per Pad $515

Per Well $4,250

Total Fees for a 12-Well Pad $51,515

FELSBURGH O L T &U L L E V I G

July 2016

City of Thornton Oil & GasTraffic Impact Fee Study

prepared by:

 

  

     

Preparedfor: 

City of Thornton 9500 Civic Center Drive 

Thornton, CO  80229‐4326        

Preparedby: 

Felsburg Holt & Ullevig 6300 South Syracuse Way, Suite 600 

Centennial, CO 80111 303.721.1440 

 

Inassociationwith: 

BBC Research and Consulting 1999 Broadway, Suite 2200 

Denver, CO 80202 303.321.2547 

    

July 20, 2016 City of Thornton Reference No. 16‐333 

FHU Reference No. 16‐075‐01    

 

     

  

 

  Pagei

TABLEOFCONTENTSPage 

I.  INTRODUCTION ....................................................................................................................... 4 

Study Purpose .................................................................................................................................. 4 

Study Area ........................................................................................................................................ 4 

Study Process ................................................................................................................................... 6 

II.  OIL & GAS DEVELOPMENT SCENARIOS ..................................................................................... 7 

Well Development Overview and Trends ........................................................................................ 7 

History of Oil and Gas Development in Colorado and Thornton ................................................... 11 

Scenario Development Methodology ............................................................................................ 17 

III.  Travel Model ......................................................................................................................... 20 

Travel Model Methodology ........................................................................................................... 20 

Inventory of Study Area Roadways ................................................................................................ 20 

Trip Generation and Truck Typology ............................................................................................. 27 

Trip Origins/Destinations ............................................................................................................... 34 

Trip Distribution and Assignment .................................................................................................. 36 

Model Results ................................................................................................................................ 37 

IV.  Transportation Impacts and Costs .......................................................................................... 43 

Unpaved Road Analysis .................................................................................................................. 43 

Paved Road Analysis ...................................................................................................................... 43 

Capacity Analysis ............................................................................................................................ 46 

Safety Analysis ............................................................................................................................... 47 

V.  Cost Recovery Mechanisms ................................................................................................... 49 

Colorado Oil and Gas Taxes ........................................................................................................... 49 

Oil and Gas Impact Fees ................................................................................................................. 51 

Other Oil and Gas Fees and Charges .............................................................................................. 55 

Special Agreements and Direct Contributions ............................................................................... 56 

VI.  Thornton Oil and Gas Roadway Impact Fee ............................................................................ 57 

Fee Calculation Methodology ........................................................................................................ 57 

Oil and Gas Roadway Impact Fees ................................................................................................. 58 

Impact of Water Pipelines ............................................................................................................. 62 

ESAL Impact Fees ........................................................................................................................... 62 

 

Appendix A.  References Appendix B.  Interview Summaries Appendix C.  Oil and Gas Trucks Appendix D.  Oil and Gas Development Scenarios Appendix E.  Travel Model Assumptions  

  

 

  Pageii

LISTOFFIGURESFigure 1.  Study Area ................................................................................................................................. 5 

Figure 2.  Study Process Diagram .............................................................................................................. 6 

Figure 3.  Approximate Time Schedule to Develop One Well on One Pad Site ...................................... 10 

Figure 4.  Active Colorado Oil & Gas Wells.............................................................................................. 12 

Figure 5.  Active Oil & Gas Wells by County, June 2016 .......................................................................... 12 

Figure 6.  Total Drilling Rigs Running in Colorado, 2003‐2016 ................................................................ 13 

Figure 7.  Well Drilling Techniques .......................................................................................................... 14 

Figure 8.  New Directional and Horizontal Wells within Thornton Study Area ....................................... 14 

Figure 9.  Average Horizontal Borehole Length in Adams and Weld Counties, by Year ......................... 15 

Figure 10.  Average Wells per Pad within Thornton Study Area ............................................................... 16 

Figure 11.  Oil and Gas Formations in Thornton Study Area ..................................................................... 16 

Figure 12.  Example of a Well Pad Configuration within the Thornton Study Area .................................. 17 

Figure 13.  Thornton Oil and Gas Development Scenarios ....................................................................... 19 

Figure 14.  Study Area Road Network ....................................................................................................... 21 

Figure 15.  Restricted Roadways ............................................................................................................... 23 

Figure 16.  Pavement Conditions .............................................................................................................. 24 

Figure 17.  Weight & Height Restricted Bridges ........................................................................................ 26 

Figure 18.  Flexible Pavement ESAL Equation ........................................................................................... 32 

Figure 19.  Rigid Pavement ESAL Equation ................................................................................................ 32 

Figure 20.  Estimated Oil & Gas Annual Average Trips per Day ................................................................ 38 

Figure 21.  Average Daily Trips by Stage – 1 Pad, 12 Wells ....................................................................... 39 

Figure 22.  Peak Impact Development Trips (Scenario A Year 8) .............................................................. 40 

Figure 23.  Peak Impact Production Trips (Scenario A Year 10) ................................................................ 41 

Figure 24.  Pavement Condition Rating ..................................................................................................... 44 

Figure 25.  AASHTO Equation for Flexible Pavements .............................................................................. 45 

Figure 26.  School Locations Compared Against Oil and Gas Routes ........................................................ 48 

Figure 27.  Calculation of Colorado Severance Taxes ............................................................................... 49 

Figure 28.  Colorado Severance Tax Distribution ...................................................................................... 50 

Figure 29.  Colorado County and Sub‐County Severance Tax Distribution ............................................... 50 

Figure 30.  Annual Thornton Severance Tax Revenues ............................................................................. 51 

Figure 31.  Thornton Oil and Gas Road Impact Fee Calculation Methodology ......................................... 57 

 

  

 

  Pageiii

LISTOFTABLESTable 1.  Thornton Oil and Gas Development Baseline Assumptions.................................................... 18 

Table 2.  Thornton Oil and Gas Development Scenarios, 10‐Year ......................................................... 19 

Table 3.  National Data of Trip Generation Per Well ............................................................................. 27 

Table 4.  Trip Generation Estimates for Various Pad Configurations .................................................... 29 

Table 5.  Trip Generation Sensitivity for Single to Multi‐Well Pad Conversion ..................................... 30 

Table 6.  Types of Trucks Used for Oil and Gas Activity ......................................................................... 31 

Table 7.  Example of Determining a Truck’s ESAL Factor for a Flexible Surface .................................... 32 

Table 8.  Typical Truck Types by Development Phase ........................................................................... 33 

Table 9.  Assumptions for Existing Pavement Sections .......................................................................... 44 

Table 10.  Costs to Offset Oil and Gas Activity by Scenario and Year ...................................................... 46 

Table 11.  Oil and Gas Impact Fee Schedule ‐ Rio Blanco County, Colorado ........................................... 53 

Table 12.  Oil and Gas Transportation Impact Fee Schedule ‐ Boulder County, Colorado ...................... 53 

Table 13.  Oil and Gas Development Impact Fee Schedule per Well ‐ Greeley, Colorado ...................... 54 

Table 14.  Thornton Oil and Gas Roadway Impact Costs After Ten Years ............................................... 58 

Table 15.  Thornton Annual Oil and Gas Roadway Impact Costs, by Year and Development Scenario ................................................................................................................................... 59 

Table 16.  Ten Year Cumulative Oil and Gas Roadway Impact Costs, by Scenario .................................. 61 

Table 17.  Ten Year Average Oil and Gas Roadway Impact Costs per Pad and Well, by Scenario ........... 61 

Table 18.  Thornton Oil and Gas Roadway Impact Fee Schedule (2016$) ............................................... 62 

Table 19.  Thornton Oil and Gas Roadway Impact Fee Schedule Per ESAL (2016$) ................................ 63 

 

  

 

  Page4

I. INTRODUCTIONColorado is one of the nation’s leading energy producing states. In 2014, Colorado was the 7th largest state in total energy production, 7th in crude oil production, and 6th in natural gas production. Oil and gas energy, in particular, is a significant sector in the region. According to the US Energy Information Administration, ten of the nation’s 100 largest natural gas fields and three of its 100 largest oil fields are found in Colorado.  The state’s largest oil and gas producing area is the Denver‐Julesburg Basin, and the City of Thornton lies near this formation.  

Oil and gas development activity in and around Thornton has increased substantially in recent years. Oil and gas drilling and production can significantly impact local road systems, as well as other public infrastructure and services. The City of Thornton has commissioned this study to understand the potential impacts of oil and gas development activity on the City’s road system and to design a road impact fee to offset increased transportation maintenance and rehabilitation costs associated with road damage caused by heavy truck traffic.  

StudyPurposeWith the heightened interest in future oil and gas development activity in and around Thornton, the City has worked to research and characterize many facets of oil and gas land use. This study seeks to understand the potential impacts of oil and gas activity on the City’s roadway system, and to design a fee system as a prospective method to recover incremental costs associated with roadway impacts. 

Due to uncertainties associated with renewed oil and gas development in and around Thornton, this study considers three hypothetical development scenarios (A, B, and C) in order to provide a range of potential roadway impact costs. These hypothetical scenarios incorporate a randomization aspect in order to account for the uncertainty in future oil and gas development patterns, the broader industry and economy, trip routing sensitivity to development site locations, and the relatively small study area. The final results of this study are based on the average results of these hypothetical scenarios. This study is not intended to predict oil and gas development location or intensity. Rather it is intended to provide City staff with information about the potential impacts to the transportation system and associated costs using an informed set of hypothetical development scenarios based on the best available data.  

This study includes the design and calculation of roadway impact fees that could offset the transportation‐related damage of oil and gas development. Thornton has broad power to regulate public roads over which it has jurisdiction, derived from its status as a home‐rule municipality. The oil and gas roadway impact fees are designed and structured within these parameters in cooperation with Thornton City staff and the City Attorney’s office.  

StudyAreaFigure 1 shows a map of Thornton and its surrounding area, the local road network, municipality boundaries, and the study area. The study area is defined as the area east of I‐25, north of 120th Avenue, west of U.S. Highway 85, and south of Weld County Road 6. This area consists of approximately 65 square miles, including portions of Thornton, and Adams and Weld Counties. Recent oil and gas activity indicates that this region of the state will likely continue to be the target of new development. 

  

 

  Page5

Figure1. StudyArea

  

 

  Page6

StudyProcessTo achieve the study purpose of assessing the potential impacts to the transportation system, and calculating an appropriate roadway impact fee, a series of analytical techniques have been used. The three primary inputs to the study process are shown on the top row of Figure 2. The inventory of existing roadway conditions provides a baseline for identifying investment needs that might result from oil and gas truck impacts. The trip generation and vehicle types provide the foundation for assigning trips and vehicle loads on Thornton’s roadway network. Finally, the hypothetical oil and gas development scenarios serve to bracket the potential levels of impact based on historical rates of development and random selection of potential development site locations. 

Figure2. StudyProcessDiagram

 

All three primary inputs have been used in the development of a travel model, which assigns both oil and gas trips and loads to Thornton’s road network in the study area. Based on the results of the travel model, mitigation strategies can be identified based on incremental roadway impact costs associated with each hypothetical development scenario. After the incremental costs of roadway impact costs are calculated, a fee is designed to recover these costs during the oil and gas land use application process. 

Each box in Figure 2 represents a set of calculations, many of which require assumptions because of the uncertainties of oil and gas development in general (e.g., the intensity of development), as well as the development potential in or near Thornton. The study team has relied heavily on input from previous studies pertaining to the transportation impacts of oil and gas development. The study team also held conversations with key Thornton staff and Colorado Oil and Gas Conservation Commission (COGCC) staff for insights in establishing the hypothetical development scenarios and understanding how and where oil and gas trucks could potentially impact the City’s roads. A full list of references is provided in Appendix A.   

  

 

  Page7

II. OIL&GASDEVELOPMENTSCENARIOSWellDevelopmentOverviewandTrendsThere are five stages in the development and operation of an oil or gas well: 

1. Leasing and exploration – Obtaining mineral rights and developing a well drilling program. 

2. Pad construction – Preparing the site, including building the access road and the well pad. 

3. Drilling – The process of drilling the well to the desired depth and completing the requisite number of horizontal bores. 

4. Completion – Converting the well system to a producing well, typically by fracturing the shale and completing the production well requirements. Removing flowback water from the well pad.  

5. Production – Extracting, storing and distributing the resource.  

This process, as it is likely to occur within and around Thornton, is described in greater detail in the following sections.  

LeasingandExplorationDrilling requires acquisition of subsurface mineral rights, which are often, but not exclusively, owned apart from a property’s surface rights. Energy companies that have an interest in exploring an area for energy prospects, or extracting resources from a known reserve, must first buy or lease the appropriate subsurface ownership rights. Companies often negotiate mineral right acquisition on speculation, before the presence of productive resources is certain. In many instances, there can be aggressive leasing activity, which is followed by very little immediate development activity, or an area can be determined to be an unproductive source after a few test wells. Active mineral leasing efforts do not ensure future energy extraction. 

Geologists and petroleum engineers will target an area for exploration, typically based on nearby well development patterns, and then company representatives will seek out property owners to acquire leases. Companies often try to maintain secrecy in this process in order to reduce speculation and keep lease costs down. Most companies will try to control a large area so that multiple wells can be drilled and the economic benefits of expensive exploration, leasing, and well field development can be efficiently recovered. Often multiple companies will share in an individual well’s, or a field’s, financial returns. 

With mineral rights secured, energy companies will approach the COGCC for confirmation of a drilling and spacing plan, which suggests the area in which initial drilling will occur. Companies may approach drilling operations slowly, spending time researching and surveying to determine the best locations for individual well development. If mineral rights are secure, companies sometimes allow other operators to proceed, modifying their own plans based on their competitors’ success or failures. Many factors can influence how quickly efforts are made to determine a new field’s prospects. Geological surveys, seismic exploration, core sampling and exploratory wells are common tools used to gauge the potential productivity of a region. 

  

 

  Page8

Exploratory wells are placed in order to obtain core samples and determine the likely productivity of the target shale. Results from the exploratory wells and the geography of an individual company’s mineral rights holdings will dictate the larger field development strategy. 

PadConstructionThe first stage of development is the construction phase. In the construction phase, crews build a road to the drilling site and construct a well pad. This process requires building a gravel road and grading a pad site generally three to five acres in area. Pad sites may contain anywhere from one to twenty wells, and the total size of the pad will depend on the number of wells planned for that location. Typical pad sites can take from one to two weeks to construct. As pad size increases, so does the number of truck trips required to supply gravel and other materials. 

DrillingThe next stage of development is the drilling stage. This stage requires one drilling rig to drill the well bore into the earth and continue horizontally in the direction of the intended extraction locations. In the Thornton area, typical wells reach vertical depths of between 6,000 to 8,000 feet, and can extend up to two miles horizontally into the shale formation. New drilling technologies and techniques allow oil and gas companies to drill these wells in about two weeks on average. 

If the site is a multi‐well pad, the same single rig generally drills all wells on the pad consecutively. Occasionally, however, oil and gas companies will drill some of the wells on a pad, and return later to drill the rest. While the drilling rig transport is sensitive to the number of pads constructed, transportation of other materials including drilling fluid and materials, drilling equipment, casing and drill pipe are all “well sensitive”, meaning each well will require additional materials. The number of trips required to transport the drilling materials will increase with each well on the pad. 

 

Constructed well pad with drilling rig in the Niobrara Shale. Source: Carrizo Oil & Gas Inc. 

Active drilling rig near Greeley, Colorado. Source: Julie Dermansky for Earthworks 

  

 

  Page9

CompletionOnce drilling is complete, the drilling rig is replaced with a multitude of hydraulic fracturing equipment including blender trucks, pump trucks, water tanks, flowback water trucks and fracture sand. Most of the completion equipment is well sensitive; meaning the number of trips will increase depending on the number of wells on each pad. Well completion requires significant truck trips primarily because of the water required in fracking the wells and the disposal of flowback water. On average, well completion requires between two and four million gallons of water. A typical water truck has a capacity of between 5,000 and 6,000 gallons. Thus, on average, hauling water to the well site and flowback water away from the site requires about 1,400 one‐way trips.  

The workers first use a fracking gun to penetrate through the well casing and fracture the shale at the furthest depths of the well. Once the well has been penetrated by the fracking gun in the appropriate areas, a highly pressurized mixture of water is pumped into the fractures starting at the deepest end of the well. The fracking fluid flows through the fractures and begins to crack the shale along natural weaknesses in the rock. Proppant, usually a sand mixture, is introduced into the fractures to keep the cracks open and help oil and gas escape into the well. The workers use a series of plugs to maintain the pressure of a fracked segment and continue to frack the shale along the horizontal well. 

During this stage, between three and five million gallons of water are pumped at high pressures into the shale and then subsequently retrieved. Under the state’s Oil and Gas Commission guidelines, all water used in this process is either recycled or properly disposed of under Commission regulations. The importation of water to the well and the subsequent removal to an approved disposal site is the most truck intensive element of a well’s development. 

Completion rig and trucks on a well pad in Weld County, September 2014. 

Source: The Denver Post, 2015. 

Drilling and completion stage technology: horizontal gas well with hydraulic fracking. Source: BBC News, 2015. 

  

 

  Page10

Once each of the arms of a well is sufficiently fractured, the plugs are removed and the well is ready for production, or the extraction of oil and gas. The completion stage can take about one week, depending on the depth and horizontal extension of the well.  

ProductionOnce the well is complete, the well pad transitions to the production phase of pumping oil or gas and produced water from the well for storage, disposal or distribution. This requires the removal of completion machinery and the installation of production machinery including a wellhead, machines that separate the oil, gas and water, resource storage tanks and other well monitoring equipment. As oil and gas is pumped from the well, the contents are sent to machines that separate the oil, gas, water, and other gases. The produced water is either released into evaporative ponds or injected into underground injection wells, which often requires transport by pipeline or truck. The well maintains optimal pressure to continue the production of energy resources and is monitored by pressure gauges. If any abnormality is indicated, the well maintenance crew, located off‐site, is automatically notified. 

During the production phase, the number of truck trips required for each well drops significantly to about two truck trips per day or 730 trips annually. These trucks are necessary for minor well maintenance while larger vehicles are required for resource collection and any other major tasks supporting production. Production trips continue throughout the life of the well, possibly 15 to 25 years. In areas of highly clustered energy development, pipelines may be constructed to transport energy and produced water away from the site to common holding or distribution facilities.  

DurationofWellDevelopmentThe approximate timing of constructing, drilling and completing a traditional single‐well oil and gas well in a shale formation is between 35 and 60 days. Figure 3 shows the schedule of developing one well on one pad site. Constructing the access road and pad takes about ten days to complete. The drilling phase, including horizontal drilling, takes about two weeks to complete on average. The completion stage, including hydraulic fracturing, takes roughly one week to complete. Finally, the production phase lasts for the remaining life of the well, up to 15‐25 years. Multi‐well pads have an extended development schedule.  

Figure3. ApproximateTimeScheduletoDevelopOneWellonOnePadSite

 

 

  

 

  Page11

HistoryofOilandGasDevelopmentinColoradoandThorntonThe Niobrara‐Denver‐Julesburg Basin and the Wattenberg Field are two of the oldest and most active oil and gas plays in Colorado. The Niobrara shale formation is a large geologic zone located in the central plains of North America. The shale formation is composed of the remnants of ancient microorganisms that lived in the ancient inland sea about 85 million years ago. The geological zone spans portions of four states, including eastern Colorado, southeast Wyoming, western Nebraska and a small portion of northwest Kansas. The area is also referred to as the Denver‐Julesburg Basin. 

Mining of coal and gold in the region began in the 1850s and continued until the 1970s. In 1901, the discovery of petroleum northwest of Thornton in Boulder County introduced energy production to the region. Because of advancements in technology and growing demand, oil and natural gas extraction began to dominate resource extraction activity in the basin. As shown on the previous page, the production of natural gas in the Niobrara region occurs predominately in the Colorado counties of Weld, Yuma and Washington and in southwestern Nebraska. Oil production is scattered throughout the region with higher concentrations in the north central and southwest part of the shale formation. As of December 2012, there were 49,993 producing oil or gas wells in Colorado, over 25,000 (approximately one‐quarter) of which were in Niobrara Shale counties. A majority (about 19,700) of these wells is located in Weld County. 

Colorado Front Range resource development over the past decade has been highly concentrated in Weld County. Between April 2015 and April 2016, 1,930 drilling permits were issued in Weld County, while only a total of 157 drilling permits were issued in Adams, Arapahoe, Boulder, Morgan and Washington Counties combined, according to approved drilling permit data from the COGCC.  

 

The center of a Colorado oil field, 1902. Source: Art Source International.

Oil and gas well locations in the Niobrara Shale in Colorado. Source: COGCC GIS Well Data, June 2016. 

  

 

  Page12

ThorntonEnergyDevelopmentThe City of Thornton is located in the southern Niobrara Basin and periodically hosts exploration and drilling activity. Many national and international factors will shape future levels of drilling activity, including oil and gas prices, national economic growth prospects, and the merit of the Niobrara Shale relative to other production areas. Locally, a host of additional factors will influence how quickly efforts are made to determine a new field’s prospects. Thornton is one of several localities that lie above the Niobrara Shale. Depending on the geology of the shale, drilling could potentially occur in any part of the study area, which includes parts of the City, unincorporated Weld County to the north, and unincorporated Adams County to the east. This area is near one of the highest concentrations of currently producing wells in the state. See Figure 1 for the study area and local boundaries. 

RecentTrendsinOilandGasDevelopmentOver the past 15 years, oil and gas development in the state has steadily increased. Figure 4 provides data from the COGCC on active oil and gas wells in Colorado. 

Figure4. ActiveColoradoOil&GasWells

 

The most significant portion of this development has occurred north of Thornton in Weld County, which is part of the Niobrara‐Denver‐Julesburg Basin and Wattenberg Field. As of June 2016, Weld County accounted for about 42 percent of the state’s 53,749 active wells, as seen in Figure 5. 

Figure5. ActiveOil&GasWellsbyCounty,June2016

 

0

5,000

10,000

15,000

20,000

25,000

Weld Garfield Yuma La Plata Las Animas Rio Blanco 36 Others

Source: COGCC Weekly and Monthly Oil and Gas Statistics, June 1, 2016. 

Source: COGCC Weekly and Monthly Oil and Gas Statistics, June 1, 2016. 

  

 

  Page13

RigUtilization

Drilling rigs are a large capital investment for any oil and gas development company, and rig purchases or rental costs represent a significant barrier to entry into the industry. According to Baker Hughes, an oil field service company that tracks operational drilling rigs, there were 421 drilling rigs operating in the U.S. on June 24, 2016. Of those active rigs about 20, or 5% of the national total, were operating in Colorado according to the COGCC. Currently, 13 of Colorado’s active rigs are located in Weld County. Figure 6 provides the number of drilling rigs in operation in Colorado from 2003 to 2016, showing that the number of active drilling rigs peaked in Colorado at around 140 rigs in Fall 2008, before dropping precipitously with the onset of the recession in 2009‐2010. From early 2009 to Spring 2015, active Colorado rigs hovered between 40 and 80, before plummeting again as oil prices fell dramatically in late 2015. Rig counts are currently at a 13‐year low point. 

Figure6. TotalDrillingRigsRunninginColorado,2003‐2016

 

Because oil and gas companies have finite capital resources and operating a drilling rig is expensive and requires a significant capital commitment, operators will allocate drilling rigs to areas that show the most promise in developing a productive well. Depending on their land holdings, oil and gas companies will consider several areas along the Front Range, Western Slope and across the nation, when deciding where to drill. In order to better understand the current characteristics of oil and gas development in the Thornton study area, the study team met with COGCC well permitting staff and reviewed available COGCC data.  

In the past, the typical well development techniques within the study area primarily utilized directional and vertical wells, drilled to reach targeted resource deposits. However, horizontally‐drilled wells, combined with hydraulic fracturing (fracking), are becoming the regional industry standard, as energy companies have learned that is the most effective method to extract hydrocarbons from shale formations. 

Figure 7 illustrates the various types of drilling techniques seen in the Niobrara‐Denver‐Julesburg Basin and Wattenberg Field. 

 

Source: COGCC Weekly and Monthly Oil and Gas Statistics, June 1, 2016. 

  

 

  Page14

Figure7. WellDrillingTechniques

 

Since 2010, the industry has made a major shift away from vertical and directional well drilling; beginning in 2013 there have been no new vertical or directional wells drilled, only horizontal wells, as illustrated in Figure 8. During 2013, one of the busiest years in recent history for oil and gas development in the Greater Wattenberg Area (GWA), the study area saw a total of 40 new wells drilled. As oil prices plunged and domestic activity slowed in 2015, only four new wells were developed in the study area. 

Figure8. NewDirectionalandHorizontalWellswithinThorntonStudyArea

 

As oil and gas companies shifted to using horizontal drilling exclusively within the study area, the characteristics of horizontal wells have also evolved. Figure 9 reveals that the average well borehole length for horizontal wells in the study area has increased significantly in the past ten years, from less than 9,000 feet in 2006 to over 13,000 in 2016. As the average length of wells increases, more water and 

Source: Energy Information Administration, Office of Oil and Gas 

Source: COGCC 

  

 

  Page15

materials are needed for drilling and fracking. However, improvements in drilling techniques mean that longer wells do not necessarily take longer to drill. According to the COGCC, a typical well in the Thornton area with a 1‐ to 1.5‐mile horizontal extension in this area can be drilled in as few as 5 days, although the typical drilling time is about 2 weeks. 

Figure9. AverageHorizontalBoreholeLengthinAdamsandWeldCounties,byYear

 

The typical well configuration of oil and gas development pads in the study area has also evolved in recent years. Historically, most pads were fully developed by one rig in a single visit. However, COGCC and Thornton staff noted that another common practice is to drill only half of the wells on a pad developed at first, and then bring the rig back several months later to drill the remaining wells.  

As market conditions favored denser drilling patterns, and new technology and techniques made it easier to drill wells faster and deeper, oil and gas companies have begun drilling more wells per pad. Since 2014, the average number of wells on each new pad has increased from around 5, to almost 15 in 2016. While conversations with the COGCC and Figure 10 suggest this trend is increasing, it is difficult to generalize development across different developers and geographies.  

 

Source: COGCC 

  

 

  Page16

Figure10. AverageWellsperPadwithinThorntonStudyArea

 

Regulations regarding the location and spacing requirements for oil and gas wells are developed and enforced by the COGCC under the 318A Spacing Rules. These regulations limit the maximum number of wells to 16 per square mile, per formation, with a minimum distance of 460 feet between wells. However, there are three major producing formations within the study area that oil and gas companies currently target; the Niobrara, Codell, and Greenhorn formations, illustrated in Figure 11. Furthermore, the COGCC can grant exceptions to the 318A Spacing Rules on a case‐by‐case basis. Due to these factors, there are many cases where well density exceeds 16 within a single square mile. In one extreme case, there is a square mile in Weld County with 67 wells, and wellheads as close as 13 feet to one another.  

Figure11. OilandGasFormationsinThorntonStudyArea

 

This high‐intensity development pattern is common in Weld County above the Wattenberg Field “sweetspot,” and can also be observed within the study area. Figure 12 illustrates an area near Thornton with two pads and 25 wells. The green areas represent Thornton city limits; the blue area is unincorporated Adams County, and the red lines represent horizontally drilled wells. Other square miles within the study area have as many as 47 active wells, though some of these include older vertical or directional wells. 

Source: COGCC 

Source: WellServicingMagazine.com 

  

 

  Page17

Figure12. ExampleofaWellPadConfigurationwithintheThorntonStudyArea

 

ScenarioDevelopmentMethodologyIn order to derive three hypothetical well development scenarios, the study team reviewed information from multiple sources, including local news outlets, energy company investor literature and the COGCC. The study team also examined historic well development with the study area to validate the hypothetical development scenarios. The goal of this review was to document current well drilling activity and field spacing patterns and trends within the study area.  

Hypothetical development scenarios were derived by mapping the current geographic distribution of wells within the study area, and determining potential well development locations and densities, given expected well spacing patterns. The study team also used COGCC data on the rate of new active wells in the area to derive an estimate of the potential pace of new well development over a 10‐year period. 

ThorntonDevelopmentScenariosIn order to account for a wide and uncertain range of potential oil and gas development drilling rates and pad locations, the study team used historic development activity and observed well spacing in the study area to develop three hypothetical oil and gas development scenarios.  

The study team examined the rate of oil and gas development within the study area in recent years to determine a range for the potential number of new wells per year. Focusing only on horizontal wells, the study area saw a total of 40 new wells drilled during 2013, one of the busiest years in recent history for oil and gas development in the study area.  As oil prices declined and domestic activity slowed, the study area had only 4 new wells in 2015. These figures provide the basis for the annual rate of new horizontal wells in each of the hypothetical development scenarios.  

Oil and gas roadway impacts are extremely sensitive to the location of development within the small study area. Some well pad locations in the study area might require no use of Thornton’s roads, while other locations might result in extensive use. Since the location of future oil and gas well pads is uncertain, the study team examined the current geographic distribution of wells within the study area, as well as the location of residential neighborhoods and schools, to identify potential sites that would not violate spacing or zoning rules. The study team used a random selection process to identify new development sites in each year for each hypothetical development scenario to account for this uncertainty, described in further detail in Section III. 

Source: COGCC 

  

 

  Page18

Based on the characteristics of oil and gas development in the study area described above, energy companies have constructed a maximum of three pads per square mile, each with an average of 12 wells per pad. Given this typical configuration, the maximum development capacity within the 65 square mile study area is 195 pads, or 2,340 wells. Table 1 presents the baseline development assumptions for the Thornton oil and gas study area. 

Table1. ThorntonOilandGasDevelopmentBaselineAssumptions

Category  Assumption 

Thornton Study Area (square miles)  65

Pads per Square Mile (max)  3

Wells per Pad (average)  12

Study Area Development Capacity (Pads)  195

Study Area Development Capacity (Wells)  2,340

Using these baseline assumptions and recent local trends described above, the study team developed a set of three hypothetical oil and gas development scenarios for the study area. This exercise is not an attempt to predict the future or quantify the likelihood of any particular scenario, but rather an effort to develop an informed set of hypothetical development scenarios based on the best available data.  

In Scenario A, three new 12‐well pads are developed each year, for a total of 36 new wells a year. This rate of development is similar to development activity seen within the study area in 2013, one of the busiest recent years. After five years, the study area would have 144 active wells in this scenario. In this scenario, it would take 65 years to reach the maximum capacity of 2,340 wells in the study area.  

In Scenario B, two pads are constructed in the first year and developed to half of their capacity (six wells), for a total of 12 wells in the first year. In the second year and all subsequent years, the remaining six wells on each incomplete pad started the previous year are developed, and two new pads are developed each with six wells (the remaining six to be developed the following year), for an annual total of 24 new wells in year two and beyond. In this scenario, there would be 84 active wells after five years, and it would take over 95 years to reach capacity. 

Finally, Scenario C is based on the rate of development in 2015. In this scenario, one pad is constructed in year one, and six wells are drilled. In the following year, the remaining six wells on that pad are drilled. The next year, a new pad is developed with six wells, and so on. The annual rate of six new wells is slightly more than in 2015, the slowest year in recent history. After five years, there would be only 24 new active wells within the study area, and it would take nearly 400 years to reach capacity. Table 2 shows the three hypothetical development scenarios over a ten‐year period. 

The year‐by‐year profile of each of the hypothetical development scenarios is shown in Figure 13. Each scenario assumes that oil and gas development would begin in Year 1 of the figure, with leasing and exploration occurring in the time leading up to Year 1. For the purpose of this study, a well’s development is assigned to a single year, and that well will be in production in all subsequent years. As the figure demonstrates, none of the scenarios achieve the maximum well capacity of the study area within the ten‐year study period. A more detailed breakdown of the hypothetical development scenarios is included in Appendix B.  

  

 

  Page19

Table2. ThorntonOilandGasDevelopmentScenarios,10‐Year

Category  Assumption 

Scenario A 

  Maximum wells per year  36

  Maximum pads per year  3

  Years of development  10

  Wells at end of analysis period  324

Scenario B 

  Maximum wells per year  24

  Maximum pads per year  2

  Years of development  10

  Wells at end of analysis period  204

Scenario C 

  Maximum wells per year  6

  Maximum pads per year  1

  Years of development  10

  Wells at end of analysis period  54

 

Figure13. ThorntonOilandGasDevelopmentScenarios

 

 ‐

 50

 100

 150

 200

 250

 300

 350

1 2 3 4 5 6 7 8 9 10

Wells Per Year

Scenario Year

In Development (Scenario A) In Development (Scenario B) In Development (Scenario C)

Operating (Scenario A) Operating (Scenario B) Operating (Scenario C)

  

 

  Page20

III. TravelModelTravelModelMethodologyA travel model has been developed using the VISUM software to assign trips and vehicle‐loads associated with the three hypothetical development scenarios (A, B, and C) to the Thornton and surrounding area roadway system. VISUM is a GIS‐based interactive computer program that assigns traffic to a network based on trip generation, trip distribution, and roadway network characteristics. Although the travel model includes roadways outside the jurisdiction of Thornton (US and State Highways, county roads, and roads in other municipalities), the transportation impacts (and associated improvement needs and costs) have been assessed only on roads under the jurisdiction of the City of Thornton.  

The most intense transportation impacts of oil and gas development occur during the well pad construction, drilling, and completion activities. For a single pad site, these three activities are estimated to occur over a nearly three‐ to six‐month period depending on the size of the pad and the number of wells. Because oil and gas development occurs year‐round, it has been assumed that the cumulative impacts of well pad development will be evenly distributed over the course of a calendar year. Therefore, all outputs from the travel model are on an annual basis. To assess the potential transportation impacts over time, the study team has evaluated four years with the 10‐year study period: Years 3, 5, 8 and 10. 

Oil and gas development will result in increased traffic on the roadway network (vehicle‐trips), as well as increased loads on the City’s roads from the many heavy vehicle trips associated with the industry. For this reason, the VISUM model has been used to estimate not only vehicle trips, but also loads as measured in equivalent single‐axle loads (ESALs). The impact of heavy vehicles is dependent on a roadway’s surface type (flexible pavement [gravel or asphalt] versus rigid pavement [concrete]). To properly calculate the ESAL impacts on Thornton’s roads, two ESAL model iterations are required; one for flexible pavement and one for rigid pavement. 

The trip generation characteristics for oil and gas development phase are substantially different from the trip generation characteristics during the on‐going well production phase. Therefore, for each evaluation year, the travel model has been run separately for the two phases. 

The assignment process was conducted for a combination of each hypothetical development scenario (A, B, and C), each analysis year (Years 3, 5, 8 and 10), for trips by phase (development and production), and for ESALs by surface type (flexible and rigid), resulting in a total of 72 iterations of the travel model. 

A summary of assumptions used to develop the travel model is provided in Appendix E. 

InventoryofStudyAreaRoadwaysThe first step in modeling the oil and gas travel on Thornton’s roadways was to understand the existing conditions of the study area roadways. The following data were collected for study area roadways under the jurisdiction of the City of Thornton, which are highlighted in Figure 14. 

 

  

 

  Page21

Figure14. StudyAreaRoadNetwork

  

 

  Page22

RestrictedRoadwaysCity staff requested that roadways with active weight restrictions be removed from the model network, as the City would prohibit oil and gas trucks from using these roadways out of concern that these roads would not be able to support any trucking traffic. The City also requested that roads classified as a collector or lower that pass in front of a school be removed, as these roads would be restricted to prevent safety conflicts between large trucks and school children. Figure 15 shows all roads that were removed from the model network for weight or school restriction purposes. The map also shows roads that were removed because they would no longer provide any useful connectivity to oil and gas traffic once restricted roads were removed. The interchange of SH 7 and US 85 was also removed due to the design restrictions that the dual roundabouts would present to oil and gas truck traffic. 

SurfaceConditionsNearly all of Thornton’s roadways that were modeled within the study area are asphalt. The only concrete road is 120th Avenue between Holly Street and Quebec Street, while portions of the following segments that are under Thornton’s jurisdiction are gravel road segments that amount to only two miles of roadway: 

152nd Avenue, Monaco Street to Quebec Street 

156th Avenue east of York Street 

Monaco Street north of 152nd Avenue 

York Street south of 168th Avenue 

Yosemite Street, 136th Avenue to Riverdale Road 

The surface condition, including the surface type and the remaining service life, significantly affect how well a particular roadway segment can accommodate heavy truck traffic. The addition of numerous heavy trucks will, over time, cause a roadway to age at a greater rate than may have been originally anticipated. In order to estimate the degree to which the schedule for improvements on these roads would be accelerated, and to provide time‐based costs of these improvements, the pavement condition index (PCI) of each paved road segment was obtained. The PCI of each road segment was used to apply a rating of either Good, Fair, or Poor condition. Figure 16 displays ratings for each paved roadway segment within the study area maintained by Thornton. No roadways were rated as Poor. 

TrafficCountsOne of the primary goals of the modeling process is to estimate traffic volumes on the City roads as a result of oil and gas activity. It is useful to compare these estimates to existing and future background traffic to provide perspective and determine if the oil and gas travel demand on any roadway segments might exceed the existing capacity. Daily traffic counts, including classification of vehicles at locations where available, were gathered from Thornton’s database and supplemented with counts available from the Denver Regional Council of Governments’ (DRCOG) traffic count database. 

BicycleFacilitiesBeing an urbanized area that borders substantial oil and gas activity, there is a potential for conflicts between bicycles using on‐street facilities and large oil and gas trucks. Thornton’s on‐street bicycle facilities were mapped to compare against modeled oil and gas traffic to determine if there might be any increased safety or level of service conflicts for bicyclists as a result of the oil and gas activity. 

 

  

 

  Page23

Figure15. RestrictedRoadways

  

 

  Page24

Figure16. PavementConditions

  

 

  Page25

BridgePostingsData from the 2015 Federal Highway Administration’s (FHWA) National Bridge Inventory (NBI) for bridges on the potential travel shed was also obtained in order to determine if there would be any weight or height restrictions that would limit use by oil and gas trucks. This information was also supplemented by bridge information received from a bridge assessment conducted by Stantec for the City of Thornton. 

Four bridges on the modeled network have a posting less than 5, meaning the load permitted under the bridge’s operating rating is less than Colorado’s maximum legal load limit. Figure 17 shows the location and posting of these bridges. The following from the 1995 FHWA Recording and Coding Guide for the Structure Inventory and Appraisal of the Nation’s Bridges describes what each bridge posting category means: 

5 – Equal to or above legal loads 4 – 0.1 to 9.9% below 3 – 10.0 to 19.9% below 2 – 20.0 to 29.9% below 1 – 30.0 to 39.9% below 0 – > 39.9% below 

Since bridges also have operational ratings that are specific to truck configurations (axle spacing, axle width, etc.), the City and the oil and gas industry should work together to ensure that actual truck types, weights, and configurations used during development and production can safely cross any bridge on a planned travel route. 

Two bridges were found to technically have a height restriction or concern, but still have a fairly substantial vertical clearance: a bridge within the I‐25/E‐470 interchange (17.3 feet) and the railroad bridge over SH 7 just west of Colorado Boulevard (16.3 feet). Figure 17 shows the location of these bridges as well. 

A listing of structures not included in the 2015 NBI inventory was also provided, but these data did not contain weight restriction data (these structures do not cross over any modeled roadways, thus do not have a height restriction in regards to this study). These bridges have been mapped with a status of unknown weight restriction. 

OtherRoadwayCharacteristicsOther important roadway characteristics for modeling oil and gas traffic included road segment length and speed limits. These factors play into the model’s shortest path routing decisions for oil and gas trips. The number of lanes and paved widths of roadways were also collected, which were used to calculate the cost of maintenance required as a result of oil and gas impacts.   

  

 

  Page26

Figure17. Weight&HeightRestrictedBridges

  

 

  Page27

TripGenerationandTruckTypologyOil and gas development requires the transport of heavy equipment to the well site to build access roads, construct a well pad and transport a drilling rig. Heavy trucks are also required to bring fresh water to the well site and often to transport produced water and extracted resources off site. The study team held conversations with several individuals that are familiar or connected with the oil and gas development in the study area, including extensive discussions with Thornton and COGCC staff.  

A literature review was also conducted to identify research related to oil and gas development and associated transportation needs. Four recent independent studies were included to inform a model of truck trip generation for oil and gas development activities in Thornton. These studies describe the number of truck trips associated with typical oil and gas development in the Marcellus Shale formation in Maryland and New York, the Uinta Basin in Utah, and the Bakken formation in North Dakota. Table 3 provides estimates of vehicle trip production by well development phase from these studies. The number of trips from each study are averaged across each phase of development and then summed to calculate trip generation estimates for this study. 

Table3. NationalDataofTripGenerationPerWell

Development 

Stages & Phases 

RESI, 2014 

1 pad, 1 well 

NYSDEC, 2011

1 pad, 1 well 

UDOT, 2013

1 pad, 1 well 

NDSU, 2014 

1 pad, 1 well 

Average 

1 pad, 1 well 

Construction 

Pad & Road Construction  230  230  1,300  160  480 

Drilling 

Drilling Rig & Crew  404  404  306  ‐  371 

Drilling Fluid & Materials  45  45  340  150  145 

Drilling Equipment 

(casing, drill pipe, etc) 45  45  34  130  64 

Completion 

Completion Rig & Crew  21  21  8  6  14 

Completion Equipment 

(pipe, wellhead, etc) 5  5  24  30  16 

Fracturing Equipment 

(pump trucks, tanks, etc) 175  175  166  260  194 

Fracture Water, Chemicals & Fluids 

1,346  846  828  900  980 

Fracture Sand  23  23  166  200  103 

Flowback Water Disposal  300  100  828  450  420 

Miscellaneous 

Other Trips  85  85  ‐  ‐  85 

Total Trips  2,871 

 

  

 

  Page28

All trip estimates in Table 3 represent the total number trips, i.e., one truck delivering water to the site accounts for two trips, one inbound and one outbound. The average trips per well data are for a specified development period of roughly one month. As described in previous sections, the average length of well boreholes has increased substantially in recent years, accompanied by an increase in truck trips to supply completion and fracking materials. The data presented above suggest that a typical horizontally‐drilled and fracked well will generate about 2,871 trips during its one‐month development period, or an average of about 93 trips per day, largely related to water delivery and removal. 

ProductionPhaseTripGenerationThere are a number of factors that determine trip generation during the production stage including the nature of the field, success of wells and storage capacity for produced water and resource at the well pad. According to a report by the Texas Department of Transportation (TXDOT) on the Barnett Shale, about 706 total trips are required per year to maintain a well (353 trucks per year). In addition, every five years another 1,994 trips (997 loaded trucks) are needed to “re‐frack” a well. This brings the annual total trips to about 1.93 trips per day, with an additional 5.5 daily trips every 5th year. However, because the frequency and extent of re‐fracking is uncertain, two trips per day are estimated over the productive life of a well. 

Multi‐WellPadSiteTripGenerationThe new regional standard practice involves drilling multiple horizontal wells per pad, with a single drilling rig completing each well. A large majority of the new oil and gas developments in the Thornton area follow this pattern, with an average of about 12 wells per pad. In order to make a reasoned and informed estimate on truck trip generation for this development approach, the project team utilized the data from the studies outlined in Table 3 to adapt trip generation estimates from the one‐rig, one‐well format, to the more common one‐rig, 12‐well configuration seen in the Thornton area. This shift in development patterns and intensity will affect traffic generation and the traffic profile associated with drilling activity by increasing well‐sensitive trips such as fracking water and drilling fluid hauling, while pad‐sensitive trips for construction and drilling rig transport remain constant. By segregating truck trips into development phase and activity, the study team estimated the total truck trips for various configurations of pads and wells. Table 4 presents truck trip estimates for multiple configurations. Table 5 shows trip sensitivity by development stage as described in a 2009 study by the National Traffic Consultants, Inc. 

A typical 12‐well pad will generate nearly 23,000 truck trips during the development phase. The trips per phase and activity for this pad configuration was the basis for the trip generation used by the travel demand model. 

 

  

 

  Page29

Table4. TripGenerationEstimatesforVariousPadConfigurations

Development Stages & Phases 

Average

1 pad 

1 wells 

Average

1 pad 

6 wells 

Average

1 pad 

10 wells 

Average 

1 pad 

12 wells 

Average 

1 pad 

15 wells 

Average

1 pad 

20 wells 

Construction     

Pad & Road Construction  480  480  480  480  480  480 

Drilling     

Drilling Rig & Crew  371  371  371  371  371  371 

Drilling Fluid & Materials  145  870  1,450  1,740  2,175  2,610 

Drilling Equipment 

(casing, drill pipe, etc) 64  381  635  762  953  1,143 

Completion     

Completion Rig & Crew  14  14  14  14  14  14 

Completion Equipment 

(pipe, wellhead, etc) 16  16  16  16  16  16 

Fracturing Equipment 

(pump trucks, tanks, etc) 194  194  194  194  194  194 

Fracture Water, Chemicals & Fluids  980  5,880  9,801  11,761  14,701  17,641 

Fracture Sand  103  617  1,029  1,235  1,544  1,852 

Flowback Water Disposal  420  2,517  4,196  5,035  6,293  7,552 

Miscellaneous     

Other Trips  85  510  850  1,020  1,275  1,530 

Total Trips  2,871  11,851  19,035  22,627  28,015  33,403 

 

  

 

  Page30

Table5. TripGenerationSensitivityforSingletoMulti‐WellPadConversion

Development Stages & Phases  Trip Sensitivity 

Construction 

Pad and Road Construction  Pad‐sensitive 

Drilling 

Drilling Rig  Pad‐sensitive 

Drilling Fluid and Materials  Well‐sensitive 

Drilling Equipment (casing, drill pipe, etc)  Well‐sensitive 

Completion 

Completion Rig  Pad‐sensitive 

Completion Fluid and Materials  Well‐sensitive 

Completion Equipment (pipe, wellhead, etc)  Pad‐sensitive 

Fracturing Equipment (pump trucks, tanks, etc)  Pad‐sensitive 

Fracture Water  Well‐sensitive 

Fracture Sand  Well‐sensitive 

Flowback Water Disposal  Well‐sensitive 

TruckTypesandImpactsThe number of truck trips might be what is most visible to the public when it comes to oil and gas development, but the weight and how it is distributed across a truck is what impacts roadway surfaces. To analyze impacts on a roadway, an ESAL factor is derived for each vehicle. Roadways are designed according to an estimated number of ESALs it will experience within a given timeframe. 

A variety of vehicle types are used for oil and gas activities, many of which are specialized and/or of significant weight, resulting in ESAL factors greater than many typical truck types. Trucks often differ between manufacturers and evolve as drilling techniques quickly advance. In order to determine how oil and gas trucks impact roadways, it’s important to understand as much as possible the different types of trucks used, their weights and configurations, and volumes within each development phase. 

TruckTypes

Although many studies and reports document truck trip generation for oil and gas activities, many do not provide significant detail on the types of trucks used or how their weight is distributed across each axle – an important detail in calculating a truck’s impact on roadway surfaces. Some of the resources consulted provide both axle and weight characteristics, but most provided only one or partial information, and required estimations based on other similar configurations. A combination of resources from the United States Department of Transportation (USDOT), Rio Blanco and Arapahoe counties, NDSU, the North Dakota Department of Transportation (NDDOT), and equipment manufacturers such as Putzmeister were consulted to determine truck types and their assumed weight configuration (total empty and full, per axle). 

   

  

 

  Page31

Table 6 provides a complete list of trucks estimated to be used for oil and gas activity. Some of the trucks listed are specific truck types by unique names, while others are generic to help standardize otherwise variable names and types used, and to allow for similar vehicles to be grouped together and applied to multiple development stages and phases. In total, nearly forty unique truck types were identified through this research effort. 

Table6. TypesofTrucksUsedforOilandGasActivity

Acid Pump  Derrick  Mud Boat  Shaker Skid 

Acid Tanker  Draw Works  Mud Pump  Shaker Tank/Pit 

Cement Pump  Frac Tank  Mud Tank  Substructure, etc. 

Cement Truck  Fuel Tanker  Oil Tanker  Suction Tank 

Chemical Tanker  Generator House  Pickup  Tool Room / Junk Box 

Choke Manifold  Gravel Haul Truck  Pipe Haul Truck  VFD House 

Construction Equipment Haul Truck 

Hydraulic Unit  Pump Truck  Water Tanker 

Control Van  Light Plant  Sand Haul Truck  Wireline 

Crown Section  MCC House  Screen House  Workover Rig 

 

 

TruckImpacts

All of the truck trips presented earlier in this chapter can have varying levels of impact. The load impact of oil and gas trucks can be as much as 15,000 to 46,000 times that of a passenger car depending on truck configurations described above and the surface type of the roadway. To account for the load impacts, ESALs for each truck type listed in Table 6 have been estimated for flexible (asphalt) and rigid (concrete) surfaces, and as fully loaded and/or empty depending on the truck’s purpose, based on the assumed axle and weight configurations. 

These ESAL factors were estimated based on the Pavement Interactive’s ESAL equations for flexible and rigid surfaces, which produce ESAL factors consistent with the American Association of State Highway and Transportation Officials (AASHTO) Guide for Design of Pavement Structures that defines ESALs for different truck configurations. The axle and weight configuration of a truck is important when determining a truck’s total impact. The equations used to calculate ESALs apply to a single axle setup (single, tandem, etc.), which is applied to each axle of a truck and aggregated to arrive at the total ESAL factor. Table 7 provides an example of how ESAL factors are derived for each axle and aggregated for the entire vehicle. It also illustrates how different axle and weight configurations for the same total weight can result in different ESAL factors. The equations used to calculate ESAL factors are displayed in Figure 18 (flexible surfaces) and Figure 19 (rigid surfaces). 

 

Sources: North Dakota Department of Transportation, 2006; RPI Consulting, LLC, 2008; La Plata County, 2002; Renegade Oil & Gas Company, LLC, 2012; Bureau of Land Management, 2008; Upper Great Plains Transportation Institute, 2012; Upper Great Plains Transportation Institute, 2013 

  

 

  Page32

Table7. ExampleofDeterminingaTruck’sESALFactorforaFlexibleSurface

% of Weight/Axle1  30,000 lbs.  80,000 lbs. 

301 / 352 / 352  0.056 + 0.008 + 0.008 = 0.073  3.032 + 0.495 + 0.495 = 4.022 

151 / 402 / 452  0.003 + 0.014 + 0.023 = 0.041  0.189 + 0.857 + 1.376 = 2.422 

151 / 402 / 453  0.003 + 0.014 + 0.005 = 0.023  0.189 + 0.857 + 0.313 = 1.359 

Figure18. FlexiblePavementESALEquation

. 10

10

.  

W = axle applications inverse of equivalency factors (where W18 = number of 18,000 lb (80 kN) single axle loads)

Lx = axle load being evaluated (kips)

L18 = 18 (standard axle load in kips)

L2 = code for axle configuration (# = # of axles, x = axle load equivalency factor being evaluated, s = standard axle [single axle])

pt = “terminal” serviceability index (point at which the pavement is considered to be at the end of its useful life)

G = log .

. ., a function of the ratio of loss in serviceability at time t to the potential loss taken at a point where pt = 1.5

SN = structural number

b = 0.4 . .

. . , a function determining the relationship between serviceability and axle load applications

 

Figure19. RigidPavementESALEquation

. 10

10

.  

W = axle applications inverse of equivalency factors (where W18 = number of 18,000 lb (80 kN) single axle loads)

Lx = axle load being evaluated (kips)

L18 = 18 (standard axle load in kips)

L2 = code for axle configuration (# = # of axles, x = axle load equivalency factor being evaluated, s = standard axle [single axle])

pt = “terminal” serviceability index (point at which the pavement is considered to be at the end of its useful life)

G = log .

. ., a function of the ratio of loss in serviceability at time t to the potential loss taken at a point where pt = 1.5

SN = structural number

b = 1.00 . .

. . , a function determining the relationship between serviceability and axle load applications

D = slab depth in inches

                                                            1 Scenarios are examples only, and assume a Serviceability Index of 2.5, Structural Number of 5, and Slab Depth of 12 inches     1 = single axle, 2 = tandem axle, 3 = triple axle 

Source: Pavement Interactive, 2009 

Source: Pavement Interactive, 2009 

  

 

  Page33

MergingTripGenerationandVehicleClassificationsSome truck types are used in multiple stages and phases, while others are used only once. And for those trucks operating within more than one phase, their number of trips varies by phase. This variation requires each phase to have a vehicle classification profile where truck types, trip shares, and impacts are linked. 

The truck configuration profiles were linked with their respective phase using available information from the resources used for determining truck trip generation and types along with additional input from a report produced by the Montana Department of Transportation (MDOT) and EIS studies from La Plata County in Colorado and the United States Department of the Interior’s Bureau of Land Management (BLM) in Utah. 

Because descriptions were not always available as to exactly which trucks are used for each phase, the reports and studies consulted were used to produce a best estimate as to how trucks are used. These resources were also referenced to estimate the average share of a phase’s trips that each truck configuration would account for, and if the truck is loaded for inbound, outbound, or both trip directions. 

Table 8 summarizes the types of trucks used by development stage and phase. Not shown in the table are truck types for the production period, which is primarily made up of pickup or similar trucks for maintenance and 5‐axle haul trucks to handle resources and flowback water. 

Table8. TypicalTruckTypesbyDevelopmentPhase

Development Stages & Phases  Truck Types 

Construction 

Pad and Road Construction  Pickup, 5‐axle haul 

Drilling 

Drilling Rig  Pickup, Specialty (6+ axles) 

Drilling Fluid and Materials  3‐axle haul, 5‐axle haul 

Drilling Equipment (casing, drill pipe, etc)  3‐axle haul, 5‐axle haul 

Completion 

Completion Rig  Pickup, Workover Rig 

Completion Fluid and Materials  3‐axle haul, 5‐axle haul 

Completion Equipment (pipe, wellhead, etc)  3‐axle haul, 5‐axle haul 

Fracturing Equipment (pump trucks, tanks, etc)  3‐axle haul, 5‐axle haul 

Fracture Water  5‐axle haul 

Fracture Sand  5‐axle haul 

Flowback Water Disposal  5‐axle haul 

 

 

 

Source: RPI Consulting, LLC, 2008; New York State Department of Environmental Conservation, 2011; Bureau of Land Management, 2008; La Plata County, 2002; North Dakota Department of Transportation, 2006; Upper Great Plains Transportation Institute, 2012; Upper Great Plains Transportation Institute, 2013; Bureau of Land Management, 2006; Upper Great Plains Transportation Institute, 2010; Bureau of Land Management, 2011; STE, 2012 

  

 

  Page34

TripOrigins/DestinationsTrip origins and destinations were identified by determining where oil and gas development trips will likely be traveling to and from. For all trips, the pad site serves as either the point of origin or the destination. Trips will either involve a loaded truck delivering items to the site, removing elements to an off‐site location, or transporting workers and machinery to and from the pad. Based on the geological formation and discussions with City of Thornton staff, all wells were assumed to be located within the study area boundary (see Figure 1). 

PadLocationsGiven the uncertainty of where oil and gas pads may be developed within the study area, the area was divided into one‐mile sections, and one potential site for pad development was assumed to be located within each section. The location of a pad within a section was assumed to be near the center of the section if little development exists in that section, with a location lying outside of the City Limits given preference if the terrain allowed since areas outside of municipal boundaries typically provide better access and an easier permitting process. In sections where development exists, the pad was placed at a location where the greatest amount of buffer existed between the pad and development, again giving preference to land outside of the City Limits, and away from schools if possible. Some pad sites along E‐470 fell outside of their respective section due to access issues and the location of the tollway, but are within close proximity to the section they represent. 

PadSelectionIn order to model where trucks would likely travel, pad sites had to be selected for each analysis year of each scenario. This selection allows the trips to be distributed across the study area at locations where oil and gas could occur within the three hypothetical development scenarios (A, B, and C); and at a frequency depending on the year of observation. Because there is no certainty as to when pad sites would be developed and where, pad locations were randomly selected from the one‐mile sections within the study area. This selection was based on how many sites were estimated to be developed within the specific analysis year of each hypothetical development scenario. Within each scenario, pads developed in one year were carried forward as producing pads from that point forward in order to maintain the reality of the oil and gas development and production process. 

The random pad selection process utilized a weighted probability structure that assigned a score to each pad site to account for the impact of the section’s existing well density and population density might have on oil and gas development potential. The higher the well density of an area, the less capacity for new wells could exist. Similarly, the higher the population density, the less likely the industry might develop nearby to avoid conflicts or the more disruptive their development activities would need to be compared to more open lands. 

To calculate a relative probability, each section was assigned a score based on its densities relative to the sections with the highest well and population densities. The relative densities were then calculated for each site as a percentage of the maximum, and an exponential function was then utilized to place more emphasis on higher population densities since population density is seen as the greater barrier to development in the study area. 

  

 

  Page35

Once scores were generated for all potential pad sites, a weighted random selection tool was used to “draw” a raffle for each analysis year of each scenario to determine which site developed that year. Once a pad site “won” the raffle and began development, it was removed from the list of eligible pad sites and carried on as a producing pad site in subsequent years of that scenario. The same selection process was conducted to determine pad sites producing in the analysis year that theoretically had been developed in prior years not analyzed, which were also carried forward into subsequent years of that scenario. With active pads for the development and production phases identified for each analysis year of each scenario, the trips and ESALs for those pads could then be applied. 

OtherOrigins/DestinationsLocations of the other end of oil and gas trips were estimated by categorizing and researching the reasons for travel (trip purposes). There are four primary trip purposes associated with oil and gas development, each of which uniquely impact where oil and gas trucks will travel:  

Bringing fresh water to the site 

Removing produced water from the site 

Transporting equipment 

Transporting other materials 

FreshWater

Water is a key resource in the well drilling process as well as during the high pressure fracturing stage, where water is mixed with sand and chemicals. For oil and gas development in and around Thornton, fresh water would likely be purchased from local water providers or private water sources catering to the oil and gas industry, primarily located north in Weld County where such operations are prevalent. The City noted that it would not authorize the sale of municipal water to oil and gas development, and no other known water sources were identified within the study area. Given that numerous small water sources could be just outside of the study area and the uncertainty of which would be used for any given development project, it was assumed that oil and gas developers would acquire water from outside of the study area to the north along the US 85 corridor, where a variety of oil and gas suppliers exist given the higher density of development along this corridor. 

ProducedWater

Water is also a major byproduct of both the development and production phases. Produced water from the fracturing process and from the extraction of oil and/or gas is generated and must be appropriately treated. Based on an interview with the head of COGCC’s Underground Injection Well Unit, for most fields in Colorado’s Front Range, roughly 20 percent of the produced water is put into onsite evaporation ponds, another 20 percent is typically either discharged to local water bodies (if it meets quality standards) or used as dust abatement on dirt roads. The remaining 60 percent is usually injected into underground injection control (UIC) wells. Colorado has roughly 800 UIC wells, with the nearest UIC wells located in Weld County. Thus it was assumed that produced water that needs to be removed from the site would be trucked to Weld County, primarily via US 85. 

 

  

 

  Page36

Equipment

The equipment required for oil and gas development, including the drilling rig, the well structure, pumps, and well casings, could come from any location where oil and gas companies have operations, or where contractors providing such services are located. This equipment is ever moving from site to site or between storage locations and new sites. With this in mind, three sources were identified as likely suppliers of oil and gas equipment. The first and primary is the US 85 corridor north of the study area, where numerous oil and gas related companies have operations. 

The other two sources include areas south of the study area via I‐25 and I‐76 where industrial operations are prominent, and along I‐25 to the north to capture transport from other oil and gas sites. Equipment could also come from the Gulf of Mexico region. Some specialty equipment is scarce in Colorado and may be brought in from other regions with a greater supply. Places such as Louisiana and Texas have previously been identified as possible source locations for such equipment for oil and gas operations in Utah, so such travel patterns could exist for operations in Colorado as well (Kuhn, 2006). The potential for these trips are captured in the southern access assumption. However, these alternative north and south sources were assumed to supply minimal trips since many industry operations exist along or near the US 85 corridor. 

Materials

Oil and gas development requires a variety of other materials in addition to water. Gravel, sand, piping, cement, chemicals, and other construction materials must be trucked to the site at different stages of the development phase. These resources would likely come from where supply is the greatest, trucking distance is shortest, and prices are the cheapest. Because these factors create a great deal of uncertainty as to where a resource may arrive from, it has been assumed that materials would arrive primarily via US 85, where numerous material outfits exist to supply the industry. A small number of trips were assigned to the south to account for industrial suppliers in areas such as Commerce City. 

TripDistributionandAssignmentWith trips per pad site and their vehicular makeup established, the three hypothetical development and production scenarios could be modeled. To model where trips would go and the impacts they would generate, trips and ESALs were loaded (separately) in the VISUM model. This process consists of two primary steps: distributing the trips and ESALs, and assigning them to the network.  

 

An oil derrick being hauled. Source: Colorado Motor Carriers Association 

  

 

  Page37

TripDistributionOnce the trips and ESALs per pad were calculated, they were entered into the VISUM travel model at each pad, distributing trips and ESALs to origins and destinations based on activities as described previously. Because of the density of oil and gas operations along the US 85 corridor, as described in the section above, a majority of trips were sent to/from US 85 to the north, while small percentages of trips were sent south towards the industrial operations in Commerce City and other possible locations along I‐25 to the north. The following percentages were generally used in distributing trips between these three external nodes: 

US 85 to the North:  85% 

South via I‐25/I‐76:  10% 

I‐25 to the North:    5% 

These splits were generally used, with minor adjustments depending on the truck type and where origins/destinations for those particular trucks were known to exist or not exist. 

TripAssignmentWith trips and ESALs distributed and linked, the VISUM travel model was used to assign the trips and ESALs to the network based on which path would provide the shortest travel time using the roadway characteristics provided, such as speed limits and distances. Because oil and gas trips take place at all hours of the day and every day of the week, background traffic and congestion were not factored into the model’s assignment.  

The assignment process was conducted for a combination of each scenario level (A, B, and C), each analysis year (Year 3, 5, 8, and 10), for trips by phase (development and production), and for ESALs by surface type (flexible and rigid), resulting in a total of 72 iterations of the travel model. 

ModelResultsThe VISUM travel model output the number of trips and ESALs on each road segment. Based on these model runs and exported data, the following sections summarize the results. 

TripsThe trips were modeled on an annual basis; in order to present trips in more manageable fashion, trips from both phases (development and production) were aggregated and converted to average annual daily trips by simply dividing the annual trips by 365. Figure 20 illustrates the average number of oil and gas trips per day for each scenario over the 10‐year study period. This figure depicts the cumulative trips of all pads being developed and producing wells. By dividing the annual trips evenly over the year, it is assumed that well development will be distributed over time resulting in a relatively even distribution of trips in total. It is important to note that trip generation will peak during the development phase at a particular pad site, resulting in a more profound local impact. Note that the jump after Year 1 of Scenario B is a result of that scenario’s development pace, which is two new pads per year each with six wells, with the remaining six wells being developed the following year. 

 

  

 

  Page38

Figure20. EstimatedOil&GasAnnualAverageTripsperDay

 Based on the travel model results using the pads randomly selected for each scenario year, the roads used by oil and gas development traffic are highly variable. Some corridors tend to handle the majority of these trips, while others handle only one pad’s worth or less, and this is all dependent on the location of development. Production trips tend to use more of the roadway network since there’s a greater dispersion of pad producing trips in this phase, but the amount of trips is significantly lower than the development phase since pads only produce roughly two trips per day. The highest estimated daily oil and gas truck traffic (both development and production trips) observed on a study area road was roughly 340 trucks per day, compared to roughly 170 trucks per day for the highest volume on a Thornton road. 

Although the total number of trips generated in the three hypothetical scenarios is not particularly high, the impact that a Thornton resident might experience if a well pad was developed in close proximity to their home could be significant, particularly during development. Figure 21 provides a graphical depiction of the number and types of trucks that are estimated per day for a 12‐well pad during each stage of development and production. The duration of each stage is approximate; if a development stage occurs over a shorter duration of time, the number of daily truck trips would be intensified.  

Figure 22 illustrates the magnitude of development trips on the study area roads for Scenario A in Year 8 (the peak scenario modeled in terms of impacts experienced on Thornton roadways), while Figure 23 illustrates the same information for production trips in Year 10 of Scenario A (the highest level of production trips). These maps illustrate how many oil and gas trips each road segment is expected to carry relative to the other oil and gas travel routes. Given the random selection of active pads, paths could change if active pads were rearranged. However, the arrangement tested with the VISUM travel model is as likely as any other potential arrangement of active pads given the information obtained for this study. Furthermore, routes with high volumes in these scenarios and years are major routes regardless of how pad sites are arranged, as they provide essential links that eventually must be used.

0

50

100

150

200

250

300

1 2 3 4 5 6 7 8 9 10

Average

 Tirps per Day

Scenario Year

Scenario A Scenario B Scenario C

  

 

  Page39

Figure21. AverageDailyTripsbyStage–1Pad,12Wells

  

 

  Page40

Figure22. PeakImpactDevelopmentTrips(ScenarioAYear8)

  

 

  Page41

Figure23. PeakImpactProductionTrips(ScenarioAYear10)

  

 

  Page42

VehicleMilesTraveledThe trips assigned by VISUM were also converted into vehicle miles traveled (VMT) to compare the increase in VMT caused by oil and gas operations with existing VMT on the study area Thornton roads plus predicted future VMT growth calculated using annual growth rates developed using the 2015 base and 2035 interim year DRCOG travel demand models. All VMT values were calculated for roads maintained only by Thornton in the study area. At the highest level of oil and gas development assumed in the three hypothetical scenarios, the additional VMT resulting from oil and gas trips would be less than half of one percent of the existing plus future background VMT on Thornton’s road network.  

Although the number of the trips generated by the oil and gas industry in the three hypothetical scenarios is relatively small in comparison to the existing traffic, the much greater transportation impact associated with industry is due to the weight of the vehicles. As described in the following section, the load impact of oil and gas trucks can be several magnitudes greater than that of a passenger car. 

EquivalentSingle‐AxleLoadsDue to the high impact of heavy vehicles on roads, ESALs are essential in calculating potential improvements needed and the costs associated with those improvements.  

To translate ESALs into a useable format from VISUM, ESALs from the flexible ESAL model runs were used for asphalt roads (gravel roads are analyzed based on truck volumes, not ESALs), while ESALs from the rigid ESAL model runs were used for concrete roads. ESALs from each phase were aggregated for each road segment. These final ESAL aggregations were then used in calculating reductions in the remaining service life of each analyzed road segment, forming the basis for estimating needed improvements and costs.  

To put ESAL factors for oil and gas vehicles into perspective, an average 4,000‐pound passenger vehicle (2,000 pounds per axle) has an estimated ESAL factor of 0.0004 when using the Pavement Tools Consortium’s equations for both flexible and rigid pavements. In comparison, the largest and heaviest oil and gas truck used in this study has an estimated full‐load ESAL factor of 9.0 on flexible pavement and 18.5 on rigid pavement. That is, the load impact to a road from the most impactful oil and gas vehicle is 22,500 – 46,000 times that of a passenger car. A loaded water truck (the vehicle with the highest frequency of trips to and from an oil and gas well) has an estimated ESAL factor of 1.4 on flexible pavement and 2.4 on rigid pavement, 3,500 – 6,000 times the load impact of a passenger car. 

The ESALs assigned by VISUM were also converted into ESAL‐miles traveled (a concept similar to VMT) to compare the increase in ESAL‐miles caused by oil and gas operations with existing ESAL‐miles on the study area Thornton roads plus predicted future ESAL‐mile growth calculated using annual growth rates developed using the 2015 base and 2035 interim year DRCOG travel demand models. All ESAL‐mile values were calculated for roads maintained only by Thornton within the study area. The ESAL loads for existing and future background traffic are based on existing vehicle classification counts from across the study area and typical ESAL values for medium and large truck classifications provided by CDOT. When ESAL‐miles traveled for oil and gas trucks are converted to a daily value and compared against the daily background ESAL‐miles traveled on the Thornton road network for any given analysis year, the increase over the background traffic is minimal, peaking at about one percent higher than the background ESAL‐miles traveled. 

  

 

  Page43

IV. TransportationImpactsandCostsThe mitigation measures and associated costs presented herein represent the additional costs or funding needs attributable to oil and gas traffic. They do not include baseline maintenance and/or improvement costs incurred by the City prior to substantial growth of oil and gas traffic.  

For this study, oil and gas traffic was distributed to the City’s network of roads, and an ESAL factor was applied to the associated traffic. The ESALs were determined in years 3, 5, 8 and 10 of each hypothetical scenario. Road mitigation measures and costs were then defined for the paved and unpaved roads impacted by oil and gas traffic based on the three hypothetical development scenarios.  

UnpavedRoadAnalysisMaintenance of gravel roads primarily consists of grading, dust suppression, and the addition of fresh gravel. An increase in conducting these maintenance activities depends on the increase in vehicles per day using the road rather than ESALs. Using maintenance data provided by City staff, Thornton currently applies new gravel every four years (average cost of $45,000/mile), performs dust suppression twice a year (average cost of $3,160/mile plus $1,025 fixed cost per application), and conducts grading every other month ($2,915 per grading). Different levels of additional trucks from oil and gas activities would trigger shortened maintenance schedules for these activities. However, only Year 3 of Scenario A required increased maintenance. This situation resulted in reducing the application of new gravel to two years, added four more dust suppression applications, and the need for eighteen more gradings. 

PavedRoadAnalysisTwo factors are critical in analyzing the capabilities of paved roads to accommodate additional truck traffic: the current condition of the pavement and the structural rating, which is measured through the structural number (SN). The structural number is a function of the thickness of the surface and base layers and the materials of these layers.  

The City provided the Pavement Condition Index (PCI) rating for all of the paved roads within the study area that are under Thornton’s jurisdiction. Surface treatments were not included in the improvement cost because these treatments do not have an impact on the structural ability of the pavement. However, it is noted that surface treatments aid in the prevention of oxidation of the pavement, which in turn, prolongs the life of the pavement. The following sections describe the methodology that was utilized to quantify the rehabilitation needs for hot mix asphalt (HMA) and concrete. 

HotMixAsphaltPavementMethodologyThe approach to determine the rehabilitation needs to offset the impacts of oil and gas traffic on hot mix asphalt pavement roads requires the determination of the pavement structural number (SN) for existing traffic as well as existing traffic plus oil and gas traffic.  

In order to determine the existing SN, the existing serviceability, initial serviceability, terminal serviceability, background ESAL, reliability level and standard deviation have to be defined. The existing serviceability is based on the PCI, as provided by the City, for each City‐owned roadway. The existing serviceability is interpolated based on the PCI and values shown in Figure 24. The values shown in Table 9 are based on Thornton’s design standards, CDOT design standards, and industry standards for the different roadway classifications.  

  

 

  Page44

 

Figure24. PavementConditionRating

Pavement Condition  PCI  Existing Serviceability 

GOOD  

100  4.5  4.5 

 

 Arterials 

Major Collectors 

Minor Collectors 

Residential 

 

 

 

FAIR 

80  3.5 3.25

     

POOR 

45 

2.5  2.0 

0 

Table9. AssumptionsforExistingPavementSections

Roadway Classification 

Reliability (%) 

Standard Normal Deviate (ZR) 

Resilient Modulus 

Terminal Serviceability 

Standard Deviation 

(Asphalt/ 

Concrete) 

Design ESALs 

(Asphalt/Concrete)

Major Arterial  90  ‐1.645  4,000  2.5  0.44 / 0.35 4,526,000 / 8,403,350 

Minor Arterial  90  ‐1.645  4,000  2.5  0.44 / 0.35 3,394,500 / 5,419,471 

Major Collector 

85  ‐1.282  4,000  2.5  0.44 / 0.35  547,500 / n/a 

Minor Collector 

85  ‐1. 282  4,000  2.0  0.44 / 0.35  365,000 / n/a 

Residential  75  ‐0.841  4,000  2.0  0.44 / 0.35  73,000 / n/a 

 

   

  

 

  Page45

These values are then utilized to solve for SN within the following 1993 AASHTO Guide equation for flexible pavement, which is provided in Figure 25. 

Figure25. AASHTOEquationforFlexiblePavements

log 9.36 log 1 0.20log ∆

4.2 1.5

0.40 10941 .

2.32 log 8.07 

18W = predicted number of 18,000 lbs. (ESALs)

RZ = Standard Normal Deviate

0S = Standard Deviation

SN = Structural Number

PSI = Existing Serviceability – Terminal Serviceability

RM = Subgrade Resilient Modulus (in psi)

After the SN is calculated for the existing conditions, the SN is calculated for the existing traffic plus the oil and gas traffic. The SN Deficiency is then calculated (SNCOMBINED ‐ SNEXISTING). The required pavement overlay for the oil and gas traffic is then calculated by dividing the SN Deficiency by the Standard Deviation. A cost for the required overlay was then calculated for each respective section of hot mix asphalt road using a unit cost of $150/ton. 

ConcretePavementMethodologyThe approach to determine the rehabilitation needs to offset the impacts of oil and gas traffic on concrete roads requires the determination of the pavement service life. Standard design for pavement service life is a span of 20 years. The associated ESAL for the 20‐year pavement service life are also shown in Table 9. 

Oil and gas traffic will decrease the overall pavement service life for concrete roads. The amount of this decrease is calculated as a percentage and based on the calculated ESAL amount for oil and gas traffic divided by the overall Design ESAL. This percentage is then multiplied by the improvement costs per lane‐mile ($650,000 was used for this study) to reconstruct a concrete pavement road in its entirety. 

 

 

  

 

  Page46

ImprovementCostsUsing the methodologies described earlier to assess the impacts estimated by the VISUM model, improvement costs as a result of the development phase were calculated for each Thornton roadway segment in each hypothetical scenario. Table 10 lists the development costs by scenario and year. 

Table10. CoststoOffsetOilandGasActivitybyScenarioandYear

  Year 3  Year 5  Year 8  Year 10 

Costs Required to Offset Development Impacts 

Scenario A  $154,300  $31,400  $260,500  $82,600 

Scenario B  $5,500  $113,900  $70,400  $20,300 

Scenario C  $700  $98,900  $4,100  $17,800 

Costs Required to Offset Production Impacts 

Scenario A  $5,500  $14,500  $17,100  $54,100 

Scenario B  $3,200  $12,400  $31,000  $38,900 

Scenario C  $800  $800  $15,500  $18,200 

The costs vary significantly per year in each hypothetical scenario for two primary reasons. First, each scenario has a different level of development occurring, with Scenario A having more trips per year than Scenario B, and Scenario B having more trips than Scenario C. However, the location of the pads (randomly selected) being developed in each year of each scenario plays a significant role in the total cost. Pads developed in areas not near Thornton’s City Limits might only use a few segments of Thornton’s roadway system or none at all. In contrast, a pad developed well within the City would have significantly more impacts, thus more cost. This is why a scenario year with less development can have a greater total cost compared to another scenario year with more development. Costs also vary depending on the road surfaces used. In most cases, the development traffic on gravel roads was too low to trigger any costs; Year 3 in Scenario A was the only time period in which increased maintenance on gravel roads would be required of the 12 time/scenario combinations. Likewise, few trips utilized concrete rods, with Year 8 in Scenario A being the only time/scenario combination to use concrete roads during development and Year 10 in Scenario A being the only combination during the production phase. 

CapacityAnalysisThe background traffic estimated for each roadway segment in each scenario’s analysis year was compared against the planning level capacity of that segment to determine if background traffic would cause the road to be over capacity. If not, the oil and gas traffic for that same period was added to the segment to determine if the oil and gas traffic pushes the road to exceed capacity. Only one segment exceeded capacity due to oil and gas activity: 128th Avenue between Quebec Street and Riverdale Road in year 5 of Scenario C. This is primarily due to the fact that the road was nearing capacity before oil and gas activity, and the classification downgrades to a major collector from a minor arterial, reducing its capacity. The added oil and gas truck traffic is estimated to be only 1.0 percent of the total projected traffic on this segment of 128th Avenue in Year 5. No other segment in any other scenario year exceeded capacity as a result of oil and gas activity. 

 

  

 

  Page47

SafetyAnalysisIn addition to the mitigation measures needed to offset the road deterioration, the study team investigated safety impacts on the study area road network related to oil and gas activity. The three safety‐related impacts investigated were restricted bridges (height and weight), conflicts with on‐street bicycle activity, and truck traffic using routes adjacent to schools. Weight and height restricted bridges are shown in Figure 17, while the bicycle and school analyses are described below. 

BicycleConflictAnalysisThe only roadways with on‐street bicycle facilities, thus there is likely bicycle activity, that intersect with oil and gas routing are Washington Street (from 120th Avenue to 136th Avenue) and Colorado Boulevard (from 120th Avenue to Cottonwood Lakes Boulevard). A planning level bicycle level of service (BLOS) analysis was conducted for both roadways, increasing the percent heavy vehicles variable relative to the observed oil and gas truck traffic estimated in each scenario year. In both cases the BLOS remained unchanged despite increases in the percent of heavy vehicles. That said, if oil and gas development occurs in an area where its generated traffic will likely pass along a route where bicyclists are known to travel, it is recommended that the roadway be monitored to determine if any safety concerns exist from the increase in larger, heavier trucks. 

SchoolAnalysisThe City of Thornton provided the location of each school within its City Limits and had any road classified as a collector or lower that passes in front of any school removed from the travel demand model, as they would prevent oil and gas trucks from using these roads. That said, there are schools on roads classified higher than a collector, and the travel model did place oil and gas trucks on these roadways in at least one scenario year. Figure 26 maps the location of these schools and highlights routes projected to be used by oil and gas trucks to illustrate where conflicts between school children crossing major roadways possibly used by large oil and gas trucks might exist. These areas should be monitored to determine if additional crossing improvements might be needed. Similarly, as new schools are built in Thornton, consideration should be given to the potential for oil and gas trucks to use the roads proximate to the schools. City staff should coordinate with the school district to ensure that any potential impacts are mitigated.   

  

 

  Page48

Figure26. SchoolLocationsComparedAgainstOilandGasRoutes

  

 

  Page49

V. CostRecoveryMechanismsLocal governments in Colorado have a number of tools available to recover the costs of oil and gas development impacts on public infrastructure, ranging from statewide taxes to case‐by‐case road maintenance agreements between the local government and oil and gas companies. This section provides a summary of cost recovery mechanisms. 

ColoradoOilandGasTaxesVarious taxes are levied against oil and gas development, production, and property by multiple jurisdictions. Municipalities receive tax revenues for both severance and property taxes assessed on oil and gas developers. This section discusses oil and gas taxation and revenue distributions to municipalities that can be used to mitigate costs associated with oil and gas truck traffic. 

ColoradoSeveranceTaxA severance tax is imposed on producers (or any party with a working or royalty interest) for the sale of nonrenewable natural resources such as oil, gas, coal, and metal. These taxes are collected by the State of Colorado, with a portion of the severance tax revenue allocated for distribution to local governments. The amount of revenue collected by the state and distributed to local governments depends on several factors.  

Annual severance taxes for oil and natural gas sales are based on gross income produced by all wells except “stripper wells”2. Production costs associated with transportation, processing and manufacturing are deducted from the taxable sale value to account for the costs of moving the gas from the point of severance (the wellhead; where valuation is supposed to occur) to the point of valuation (usually a regional gathering location).  

Figure 27 illustrates the calculation of gross severance tax due, based on a variable tax rate. Taxpayers may credit 87.5 percent of ad valorem taxes paid to local governments on oil and gas production to determine the net severance tax due.3,4 

Figure27. CalculationofColoradoSeveranceTaxes

 

   

                                                            2 Stripper wells produce less than 15 barrels of crude oil or 90,000 cubic feet of gas per year on average. 3 Excluding taxes related to stripper wells or taxes on buildings, improvements and equipment. 4 This credit is designed to eliminate the disincentive to invest in jurisdictions with high property taxes. 

Source: Colorado Department of Revenue. 

  

 

  Page50

State severance tax distribution is a complex process, as depicted in Figure 28. Colorado’s severance tax revenues are first split evenly between the State Trust Fund and the Local Impact Fund. The State Trust Fund provides funding for Water Conservation and Department of Natural Resources operations. The Local Impact Fund allocates 70 percent of its collections to a local government grant program that awards funding through a competitive process. The remaining 30 percent of Local Impact Fund revenue is directly distributed to local governments. 

Figure28. ColoradoSeveranceTaxDistribution

 

 

Severance tax distribution to local governments involves two steps. Funds are first allocated among Colorado counties based on their share of the state’s resource production, energy employee residence and drilling/mining permits. The second step in the distribution of state severance tax revenues is a sub‐county allocation, where the severance tax funds allocated to each county is divided among the county and its municipalities based on the proportion of the state’s road mileage, population and energy worker residence in each jurisdiction. Figure 29 demonstrates the flow of severance tax revenues from the Local Impact Fund to local governments. 

Figure29. ColoradoCountyandSub‐CountySeveranceTaxDistribution

 

 

 

 

 

 

 

Source: Colorado Department of Local Affairs. 

Source: Colorado Department of Local Affairs. 

  

 

  Page51

In 2015, the City of Thornton received $376,881 in sub‐county severance tax distributions, continuing the upward trend since 2010, seen in Figure 30 below. Based on a March 2016 count of 97 producing wells within Thornton’s city limits, the 2015 severance tax revenue per well was approximately $3,885. 

Figure30. AnnualThorntonSeveranceTaxRevenues

 

Severance tax revenues can be used for a number of purposes, including cost recovery for oil and gas activities. One example of severance tax revenues being used for oil and gas related impacts is Garfield County, Colorado, which dedicates its severance tax collections to the Oil & Gas Mitigation Fund. These funds are used on special projects related to the impacts of oil and gas development. 

Resource‐BasedPropertyTaxesLocal governments also collect property tax from oil and gas wells. Many factors influence property tax revenues from oil and gas resources, including well production levels, resource market value, and the mill levy rate. Oil and gas real property is assessed at 87.5 percent of actual value, which is significantly higher than commercial real property (29 percent) and residential real property (7.96 percent). Oil and gas personal property is assessed at the standard commercial assess rate of 29 percent. In 2015, Thornton collected $52,792 in oil and gas property tax revenues, or about $545 per producing well. 

OilandGasImpactFeesIn addition to tax revenues from oil and gas development activities, local governments may employ several other cost recovery methods to mitigate transportation impacts related to oil and gas development activities. For many local governments, the greatest impacts occur on road and bridge infrastructure due to the heavy and frequent truck traffic during well development. While local governments may receive funds though oil and gas property taxes and/or severance taxes, many jurisdictions have implemented additional methods to recover costs through statewide oil and gas impact fees, local oil and gas impact fees, truck permitting fees, road user fees and road impact agreements with the industry. 

   

$0

$50,000

$100,000

$150,000

$200,000

$250,000

$300,000

$350,000

$400,000

2010 2011 2012 2013 2014 2015

Severance Tax Revenue

Source: Colorado Department of Local Affairs. 

  

 

  Page52

LocalGovernmentOilandGasImpactFeesImpact fees are generally defined as monetary charges imposed by local governments on new development to recoup or offset a proportionate share of public capital costs required to accommodate such development with necessary public facilities. Impact fees provide a mechanism for local governments to ensure that the costs associated with new development is borne by the developers, and not the larger community.  

In 2001, the Colorado State Legislature passed Senate Bill 15, otherwise known as the Colorado Impact Fee Act. This law permits a municipality or county to assess an impact fee on a new development as long as the fees are legislatively adopted by the local government, generally applicable to a broad class of property, and intended to defray the project impacts on capital facilities caused by proposed development.  

Courts have developed standards for determining whether an impact fee is constitutionally valid. In the case of an oil and gas development roadway impact fee, a “rational relationship” must demonstrate a reasonable connection between the development fee and the roadway infrastructure. A second guideline requires that the costs of the roadway impacts covered by the fee are “specifically and uniquely attributable” to oil and gas development. Finally, the “rational nexus” test is satisfied if the jurisdiction (1) shows that oil and gas development creates the need for additional roadway infrastructure or improvements; (2) quantifies the cost of providing such infrastructure or improvements; and (3) bases the fee on the extent to which oil and gas developments benefit from the additional roadway infrastructure or improvements. 

Several localities have enacted impact fees under the Colorado Impact Fee Act. However, Thornton is a Home‐Rule Municipality, and is not bound by the requirements of the Act. Rather, the City is self‐governed by its Home Rule Charter, under Article 20 of the Colorado Constitution. Home rule municipalities are not required to follow state statutes in matters of local concern, allowing them to shape policies that best fit local needs, including the implementation of impact fees. 

Impact fees can help mitigate the lag time between well development, road damage and the receipt of property or severance tax revenue because they are typically collected during the permitting process before drilling occurs. However, there are restrictions on how impact fee funds can be used. Impact fees can only be used for capital improvements to expand the capacity of the roadway system to accommodate traffic generated by oil and gas development, such as new traffic signals, additional turn lanes, new roads, or improvements that correct existing design deficiencies. Funds may not be used to address existing deficiencies, routine operations, maintenance, or rehabilitation of the existing roadway infrastructure.  

Many counties and municipalities currently use impact fees to offset the capital expenditure necessary to accommodate residential, commercial and industrial development, although Thornton currently does not. This section examines three Colorado local governments that currently impose impact fees specifically on oil and gas development. Adams and Arapahoe counties are currently considering impact fees. It is worth noting that each of these jurisdictions also has impact fees for other types of development. 

   

  

 

  Page53

RioBlancoCounty

In 2008 Rio Blanco County commissioned a study to quantify the expected impact of oil and gas, residential, and non‐residential land uses on administrative, law enforcement, and transportation departments. Beginning in 2009, the county began imposing a one‐time impact fee for new development for each land use. Revenues collected through impact fees are deposited into a separate fund and can only be used to pay for future capital projects made necessary by new developments. Since Rio Blanco County oil and gas transportation impacts occur in a relatively localized area, these fees primarily fund improvements to those roads that are heavily utilized by oil and gas developers, providing them a direct benefit. The impact fee schedule for all land uses and county facilities in Rio Blanco is shown in Table 11. 

Table11. OilandGasImpactFeeSchedule‐RioBlancoCounty,Colorado

Department Oil and Gas Impact Fees 

Per Well  Others 

Administrative  $100  $100

Law Enforcement  $181  $181

Road & Bridge5  $17,700  $9.07 per ESAL

Total  $17,981  Varies

BoulderCounty

In 2013, the Boulder County Board of Commissioners commissioned a roadway impact fee study by Felsburg Holt & Ullevig and BBC Research and Consulting. Later that year, the Board adopted Resolution 2013‐49, establishing an oil and gas transportation impact fee. The one‐time fee is assessed on oil and gas development as a prerequisite to issuance of a Development Plan Review Construction Permit. Fee revenues may only be expended on roads impacted by heavy truck traffic associated with oil and gas development. Although this impact fee is currently effective, Boulder County implemented a moratorium on oil and gas development in 2012, so the fee has never actually been collected. Table 12 illustrates Boulder County’s fee schedule for wells and pads. 

Table12. OilandGasTransportationImpactFeeSchedule‐BoulderCounty,Colorado

Impact Fee Name  Assessed  Fee Amount 

Roadway Deterioration  per well  $17,300

Roadway Deterioration  per well pad  $700

Roadway Safety  per well  $4,000

Cost of Project (Poor Roads)  per well  $8,600

Cost of Project (Road Safety  per well  $8,000

Total    $38,600

                                                            5 Road & Bridge impact on shallow wells (less than 5,500 feet) is $10,300. 

Source: Boulder County Resolution 2013‐49. 

Source: Rio Blanco County 

  

 

  Page54

CityofGreeley

The development impact fees assessed by the City of Greeley cover a number of impacts, and apply to commercial and residential development, as well as new oil and gas wells. Fees are assessed at the time of permitting, and are designed to pay for additional infrastructure to accommodate the growth generated by all types of development. Table 13 below provides the fee schedule for oil and gas wells within Greeley city limits. 

Table13. OilandGasDevelopmentImpactFeeScheduleperWell‐Greeley,Colorado

Impact Fee Type  Amount 

Storm Drainage  $196

Transportation  $1,748

Fire and Rescue Development  $272

Police Department  $60

Total Impact Fees per Well  $2,276

IntergovernmentalAgreements

In some cases, local governments may consider entering into an intergovernmental agreement regarding the administrative responsibilities and revenues associated with impact fees. One current example of an intergovernmental agreement on impact fees can be seen between Larimer County and Fort Collins. In 2013 these two governments entered into an agreement to develop an impact fee in order to contribute funds towards the provision of adequate road facilities in the region. The County is generally responsible for the planning, implementation, and administration of the fee, with assistance from the City. In exchange, administrative fees are paid to the City as a percentage of fee revenues collected by the City.  

Since a majority of the oil and gas activity that impacts Thornton roads occurs in the unincorporated areas of Adams County and Weld County, the City may not have the authority to directly levy fees. Thornton may need to explore intergovernmental agreements with Adams and Weld counties to collect fees, such as the one between Larimer County and Fort Collins. 

StateOilandGasImpactFeesA growing number of states have also explored the merits of a statewide oil and gas impact fee. The state applies the fee on a quantification of oil and gas activity, collects the funds, and then distributes a portion of the funds to local governments for mitigation of oil and gas related impacts. In February 2012, the Pennsylvania state government passed Act 13, which enables the imposition of impact fees on horizontally fractured gas wells. Under the new legislation, the state imposes per‐well impact fees ranging from $10,000 to $50,000. 60 percent of the impact fee revenue collected by the state is distributed to the counties and municipalities where the fees were generated, with the remaining 40 percent going to statewide initiatives. Pennsylvania is currently the only state with an active state‐level impact fee for gas wells, although others, including Ohio and West Virginia, have also considered this approach. 

Source: City of Greeley Development Impact Fee Schedule. 

  

 

  Page55

OtherOilandGasFeesandChargesLocal governments may also assess other types of fees or charges to oil and gas developments to directly cover the associated costs for infrastructure, repair, maintenance, or capital improvements. 

OversizedandOverweightVehiclePermitFeesSome local governments require oversized or overweight truck permit fees to offset the impact of large and heavy trucks on local roadways. Many of these permits are valid only on the roads of the jurisdiction, although some allow movement across jurisdictions as long as each one receives payment.  

Overweight or oversized vehicle permits may be required for each one‐way or round trip, or may be purchased annually, with fees varying across jurisdictions. Adams County, for example, charges a $100 fee for a round‐trip overweight or oversized load. Boulder County charges a one‐way fee of $25 for overweight or oversized loads, with additional damage deposits required for extreme side loads. Garfield County issues single trip fees of $15 for oversized loads and $15 plus $5 per axle for overweight loads. They also offer annual oversize or overweight permits for $250, or $500 if the load is both oversized and overweight. Additional per‐trip fees also apply if the load exceeds 100,000 pounds.  

Other localities have specific permit fees for the movement of very large oil and gas rigs. The Town of Frederick, for example, requires an Oil & Gas Rig Transport Permit of $1,000 each time a rig is moved on city roads, while Adams County requires a $100 fee for each one‐way drilling rig trip on county roads, both regardless of distance.  

According to a discussion with City staff, Thornton has the ability to charge oversize and overweight fees of $25‐$35, however they are not currently collected during the permit process due to administrative burden and limited payment options. 

RoadUseAgreementsSeveral local governments have established Road Use Agreement requirements for oil and gas development. These agreements are made between the local government and the developer to define the terms and conditions under which the developer is responsible for the costs of excess maintenance and repair of excess road damage caused by their activities.  

Under a road use agreement, developers are required to submit information on the truck routes, truck types, traffic flows, and timeline associated with the development of oil and gas wells prior to commencement. Once this information is presented, representatives from the local government and the developer examine the proposed routes to determine current conditions and expected impacts. After development activities are completed, representatives from both parties again examine the routes utilized by the developer and the cost of damages is determined.  

Local governments have various processes to insure that the developer is held responsible for their share of road repairs. Some require developers to post a bond for the designated roadways, the value of which depends on the length and type of impacted roads. Elbert County requires a bond of around $30,000 per mile or gravel road, or $70,000 for asphalt roads, depending on original condition and expected impacts. Moffat County, on the other hand, may require a bond or letter of credit, depending on the impacted location and structures. 

  

 

  Page56

SpecialAgreementsandDirectContributionsLocal governments and the oil and gas industry periodically collaborate to establish agreements to fund the infrastructure required for oil and gas activity. Local governments can approach the oil and gas industry and negotiate direct monetary contributions for road projects that specifically benefit industry interests. 

VoluntaryContributionsSpecial agreements between oil and gas developers and local governments are occasionally on a voluntary basis. In Garfield County, Colorado, oil and gas companies sometimes provide additional funds to assist the Road and Bridge Department with improving or expanding infrastructure directly affected by nearby development. Arapahoe County, Colorado has established a voluntary $7,500 per well fee dedicated for road impacts. The County works with drilling companies to negotiate improvement and maintenance to roads affected by oil and gas trucking. Contributions are designated to cover the costs of road development on a case‐by‐case basis. Similar agreements have also been seen outside of Colorado, such as a voluntary $8,000 road maintenance fee per well in DeWitt County, Texas. 

RoadMaintenancePermitAnother approach, seen in Moffat County, allows developers to purchase a road maintenance permit, which allows private companies to perform maintenance on the roads they use themselves. These permits are designed to reduce the financial burden on county taxpayers for repairing road damage due to the applicants use. Permits are available for $250, however they are only issued at the discretion of the County, and require all maintenance and improvements to comply with county regulations.  

In practice, funds obtained through direct contributions can vary widely year to year, and do not necessarily provide a steady revenue stream. 

   

  

 

  Page57

VI. ThorntonOilandGasRoadwayImpactFeeThe purpose of designing oil and gas roadway impact fees is to recover the incremental costs associated with the energy industry’s impact on Thornton’s road network. Because of the nature of oil and gas development, the most intense impact occurs during the first month of a well’s life. After the development stage, the well enters the less trip‐intensive production stage. The capital required to recover the costs of the development stage is ideally recovered before development begins or during the permitting process. This is accomplished through oil and gas roadway impact fees. 

FeeCalculationMethodologyIn designing oil and gas road impact fees, it is critical to isolate the oil and gas damage on the City roads. The fees are designed to recoup the incremental cost associated with roadway impacts, and designed to be integrated into the oil and gas land use application process in the City’s newly adopted regulations. This process requires the combination of the inventory of roadway conditions, trip generation and vehicle types and hypothetical development scenarios. The fees in this study are based on a blend of the total roadway impact costs of each of the three hypothetical scenarios over ten years, and average truck trip lengths and routes.  

The oil and gas roadway impact fees are generated by first calculating the total annual roadway impact costs associated with oil and gas development and production for each year, in each of the hypothetical oil and gas scenarios. These annual costs are based on the average roadway impact cost of developing a 12‐well pad and the average impact cost of wells in the production phase. The total annual costs are then summed to give the total ten‐year roadway impact costs incurred in each scenario. The total ten‐year cost is then divided by the total number of active pads and wells at the end of the ten‐year period to calculate average annual roadway impact costs per pad and per well. The methodology for calculating the oil and gas roadway impact fees is illustrated in Figure 31. 

Figure31. ThorntonOilandGasRoadImpactFeeCalculationMethodology

 

   

  

 

  Page58

OilandGasRoadwayImpactFeesIn order to calculate annual roadway impact costs associated with oil and gas development and production, the study team first estimated the average annual impact costs for the development of a 12‐well pad, the development of a single well, and for a producing well. Table 14 provides these figures for each hypothetical development scenario. 

Table14. ThorntonOilandGasRoadwayImpactCostsAfterTenYears

Scenario  Cost 

Scenario A 

Average Roadway Impact Cost of Developing a 12‐Well Pad  $44,067

Average Roadway Impact Cost of Developing a Single Well  $3,672

Average Annual Roadway Impact Cost of a Single Producing Well  $103

Scenario B 

Average Roadway Impact Cost of Developing a 12‐Well Pad  $26,263

Average Roadway Impact Cost of Developing a Single Well  $2,189

Average Annual Roadway Impact Cost of a Single Producing Well  $157

Scenario C 

Average Roadway Impact Cost of Developing a 12‐Well Pad  $30,375

Average Roadway Impact Cost of Developing a Single Well  $5,063

Average Annual Roadway Impact Cost of a Single Producing Well  $190

These average annual costs are then multiplied by the number of developing pads and producing wells in each scenario year, respectively, to calculate the annual total oil and gas roadway impact cost. Table 15 shows the roadway impact costs associated with oil and gas development and production in each year of the study period, for each of the three hypothetical development scenarios. 

   

  

 

  Page59

Table15. ThorntonAnnualOilandGasRoadwayImpactCosts,byYearandDevelopmentScenario

Years 1 ‐ 5 

Scenario A 

  Year 1  Year 2  Year 3  Year 4  Year 5 

  Development  Production  Total  Development Production Total  Development Production  Total  Development Production Total  Development Production Total 

Total Road Impact $  $132,201  $0  $132,201 $132,201  $3,709  $135,910 $132,201  $7,418  $139,619 $132,201  $11,127  $143,328 $132,201  $14,836  $147,037

# of Active Pads  3  0  3  3  3  6  3  6  9  3  9  12  3  12  15 

# of Active Wells  36  0  36  36  36  72  36  72  108  36  108  144  36  144  180 

Scenario B 

  Year 1  Year 2  Year 3  Year 4  Year 5 

  Development  Production  Total  Development Production Total  Development Production  Total  Development Production Total  Development Production Total 

Total Road Impact $  $52,526  $0  $52,526 $52,526  $1,884  $54,410 $52,526  $5,653  $58,179 $52,526  $9,422  $61,948 $52,526  $13,191  $65,717

# of Active Pads  2  0  2  2  2  4  2  4  6  2  6  8  2  8  10 

# of Active Wells  12  0  12  24  12  36  24  36  60  24  60  84  24  84  108 

Scenario C 

  Year 1  Year 2  Year 3  Year 4  Year 5 

  Development  Production  Total  Development Production Total  Development Production  Total  Development Production Total  Development Production Total 

Total Road Impact $  $30,378  $0  $30,378 $30,378  $1,140  $31,518 $30,378  $2,280  $32,658 $30,378  $3,421  $33,799 $30,378  $4,561  $34,939

# of Active Pads  1  0  1  0  1  1  1  1  2  0  2  2  1  2  3 

# of Active Wells  6  0  6  6  6  12  6  12  18  6  18  24  6  24  30 

 

   

  

 

  Page60

Table15. ThorntonAnnualOilandGasRoadwayImpactCosts,byYearandDevelopmentScenario(cont.)

Years 6 ‐ 10 

Scenario A 

  Year 6  Year 7  Year 8  Year 9  Year 10 

  Development  Production  Total  Development Production Total  Development Production  Total  Development Production Total  Development Production Total 

Total Road Impact $  $132,201  $18,545  $150,746 $132,201  $22,254  $154,455 $132,201  $25,964  $158,165 $132,201  $29,673  $161,874 $132,201  $33,382  $165,583

# of Active Pads  3  15  18  3  18  21  3  21  24  3  24  27  3  27  30 

# of Active Wells  36  180  216  36  216  252  36  252  288  36  288  324  36  324  360 

Scenario B 

  Year 6  Year 7  Year 8  Year 9  Year 10 

  Development  Production  Total  Development Production Total  Development Production  Total  Development Production Total  Development Production Total 

Total Road Impact $  $52,526  $16,959  $69,485 $52,526  $20,728  $73,254 $52,526  $24,497  $77,023 $52,526  $28,265  $80,791 $52,526  $32,034  $84,560

# of Active Pads  2  10  12  2  12  14  2  14  16  2  16  18  2  18  20 

# of Active Wells  24  108  132  24  132  156  24  156  180  24  180  204  24  204  228 

Scenario C 

  Year 6  Year 7  Year 8  Year 9  Year 10 

  Development  Production  Total  Development Production Total  Development Production  Total  Development Production Total  Development Production Total 

Total Road Impact $  $30,378  $5,701  $36,079 $30,378  $6,841  $37,219 $30,378  $7,981  $38,359 $30,378  $9,121  $39,499 $30,378  $10,262  $40,640

# of Active Pads  0  3  3  1  3  4  0  4  4  1  4  5  0  5  5 

# of Active Wells  6  30  36  6  36  42  6  42  48  6  48  54  6  54  60 

 

 

  

 

  Page61

Once annual roadway impact costs are calculated, they are summed by scenario to generate a ten‐year cumulative roadway impact cost associated with oil and gas development and production. Table 16 below provides these cumulative costs for each hypothetical scenario, as well as the total number of active pads and wells at the end of the ten‐year period. 

Table16. TenYearCumulativeOilandGasRoadwayImpactCosts,byScenario

  Scenario A  Scenario B  Scenario C 

Ten‐Year Total Oil and Gas Roadway Impact Costs  $1,488,919  $677,893  $355,088 

Total Number of Active Pads at End of Year 10  30  20  5 

Total Number of Active Wells at End of Year 10  360  228  60 

The average overall roadway impact cost per 12‐well pad is next calculated as the total ten‐year roadway impact costs, divided by the number of active pads at the end of the period, for each scenario. The average cost per well is found by dividing the overall roadway impact cost by the number of active wells at the end of the study period. Table 17 presents the average overall development roadway impact costs per pad and per well for each scenario, as well as the overall average across all three hypothetical scenarios. 

Table17. TenYearAverageOilandGasRoadwayImpactCostsperPadandWell,byScenario

  Scenario A  Scenario B  Scenario C  Overall Average 

Average Roadway Impact Cost per 12‐Well Pad  $49,631  $33,895  $71,018  $51,515 

Average Roadway Impact Cost per Well  $4,136  $2,973  $5,918  $4,342 

 

To separately calculate the roadway impact costs of new pad construction, the project team examined the share of total pad development ESAL impacts associated with pad construction. On average, pad construction accounts for one percent of the ESALs, or $515, of the average total roadway impact costs of a 12‐well pad, equal to $51,515. These pad construction roadway impact costs are then subtracted from the total cost per 12‐well pad, and the remainder divided by 12 to calculate a per well roadway impact cost of $4,250, which includes costs associated with well development and production. Note that the per‐well impact cost is slightly reduced after excluding pad development costs. 

Table 18 presents the associated roadway impact fees for each new pad and new well. For each new pad, a fee of $515 is imposed to cover the roadway impact costs of pad construction. For each new well there is a fee of $4,250, which accounts for well development and production while excluding the impacts of pad development. 

  

 

  Page62

Table18. ThorntonOilandGasRoadwayImpactFeeSchedule(2016$)

  Roadway Impact Fee 

Per Pad  $515 

Per Well  $4,250 

Total Fees for a 12‐Well Pad  $51,515 

Based on this fee schedule, a new 12‐well pad would be imposed a total of $51,515 in roadway impact fees. Please note that the fees in this table represent the full cost recovery for roadway impacts, in 2016 dollars. To keep the fees current, it is appropriate to use a cost index, such as the Engineering News Record or CDOT construction cost index. 

ImpactofWaterPipelinesSome areas in nearby Weld County have reached a well density threshold where the industry determined it was more cost effective to use water pipelines to transport fresh water to and flowback water from the pad site. To see what this would be in terms of impacts, the trips and ESALs associated with water transport were removed from a pad’s trip and ESAL generations. This test resulted in a reduction in trips of 70 to 73 percent and a reduction in ESALS of 78 to 80 percent depending on the scenario. 

ESALImpactFeesTo provide the City with more flexibility in imposing impact fees, the study team also examined impact costs per ESAL. In the event that an oil or gas company believes they will generate lower roadway impact costs than the assessed fees above, they may perform their own traffic study to provide evidence quantifying the expected number of ESALs the development will generate, and the associated routes and distances traveled. Once the City agrees to the independent traffic study results, they may impose a fee based on the anticipated number of ESALs and number of lanes miles of the route, as opposed to the flat fees per pad and well calculated above.  

In order to calculate an oil and gas roadway impact fee per ESAL lane‐mile, the study team utilized data on ESAL impact costs for a 12‐well pad on each functional classification and pavement type in Thornton’s roadway network, as described in Section IV. For each functional class, an average cost of one ESAL per one mile of 12‐foot wide (one lane) roadway was calculated based on the average condition rating of Thornton’s study area road network for each functional classification. As of the time of this report, the average condition for each classification and pavement type in Thornton fell under the “Fair” category.  

Once these impact costs per ESAL lane‐mile were calculated for each functional classification and pavement type, the study team calculated a weighted average impact cost based on the share of Thornton’s study area road network under each classification. Table 19 lists the impact costs and proportion share of each road type. 

   

  

 

  Page63

Table19. ThorntonOilandGasRoadwayImpactFeeSchedulePerESAL(2016$)

Functional Classification and Pavement Type Percent of Thornton’s Study Area Roadway 

Network 

Average Cost perESAL Lane‐Mile 

Major Arterial (Concrete)  2%  $0.11 

Major Arterial (Asphalt)  63%  $0.52 

Minor Arterial (Asphalt)  19%  $0.72 

Major Collector (Asphalt)  8%  $2.59 

Minor Collector (Asphalt)  1%  $2.58 

Residential (Asphalt)  7%  $6.70 

Weighted Average Roadway Impact Cost per ESAL Lane‐Mile:  $1.17 

The weighted average impact cost of $1.17 per ESAL lane‐mile represents the full cost recovery amount associated with a single ESAL on one mile of a single 12‐foot lane Thornton roadway. Accordingly, this study suggests that the City may impose a fee of $1.17 per ESAL lane‐mile for oil and gas companies that submit an independent traffic study, provided that the traffic study includes details on the total number of ESALs that will be associated with development and production, and detailed routing describing the total distance and routes by which the ESALs will travel to and from the proposed pad site, broken up into sections by the number of total lanes along the route. The final fee would multiply the ESAL lane‐mile fee amount by the distance and number of total lanes for each road cross‐section used. 

FELSBURGH O L T &U L L E V I Gconnecting and enhancing communities

6300 S. Syracuse Way, Suite 600Centennial, CO 80111303.721.1440

www.fhueng.com

Thornton Oil & Gas Traffic Impact Fee Study July 26, 2016 Presentation to City Council

Oil and Gas Context oThe City of Thornton lies near the state’s largest oil and

gas producing area: Denver-Julesburg Basin oOil and gas development activity has increased

substantially in recent years oThis study examines the potential impacts of oil and gas

development on City roads, and calculates a corresponding road impact fee

Study Objectives

oIdentify potential impacts of oil and gas industry on Thornton’s roads

oEstimate general magnitude of: oOil & gas related truck traffic o Incremental road deterioration

oDevelop a cost recovery mechanism to allow the City to offset increased road deterioration costs

Study Process Diagram

Study Area

Well Development Overview and Trends

oThere are five stages in the development and operation of an oil or gas well: o Leasing and exploration

o Obtaining mineral rights and developing a well drilling program. o Pad construction

o Preparing the site, including building the access road and the well pad. o Drilling

o The process of drilling the well to the desired depth and completing the requisite number of horizontal bores.

o Completion o Converting the well system to a producing well, typically by fracturing the shale

and completing the production well requirements. Removing flowback water from the well pad.

o Production o Extracting, storing and distributing the resource.

Service Delivery Challenges oOil & gas industry has unusual characteristics…

oDispersed oRoad intensive oMigratory oEvolving: drilling

to production oUncertain pace and

intensity of development oUncertain traffic patterns

Hypothetical Development Scenarios oThree hypothetical development scenarios account for a wide range

of potential development patterns o Rates of development based on historical trends o Randomized development site selection

oScenario A o Three new pads w/ 12 wells each, per year o 144 active wells after five years

oScenario B o Two new pads w/ six wells each, per year o Remaining six wells on each pad completed in following year o 84 active wells after five years

oScenario C o One new pad w/ six wells, every other year o Remaining six wells on each pad completed in following year o 24 active wells after five years

Development Site Selection oUncertainty as to where and when pad sites will be

developed oStudy team designed random site selection process oOne potential site per square mile identified

oEach assigned a probability score based on current well density and population density

oRandom Site Selection based on probability score

Hypothetical Development Scenarios: New and Producing Wells

-

50

100

150

200

250

300

350

1 2 3 4 5 6 7 8 9 10

Wel

ls P

er Y

ear

Scenario Year

In Development (Scenario A) In Development (Scenario B) In Development (Scenario C)

Operating (Scenario A) Operating (Scenario B) Operating (Scenario C)

Annual operating wells accumulate over time as new wells are drilled and completed

Trip Generation – Clustered Development o Literature Review examined

National studies on truck trip generation, by phase oAssumes clustered

development, horizontal drilling, hydraulic fracturing o Study findings adapted to

observed patterns in Study Area oTwelve wells per pad

oBorehole depths

Average Daily Trips by Stage – 1 Pad, 12 Wells

Travel Model Roadway Network

Transportation Impacts Considered oCapacity oSafety

oBicycle conflicts oSchool proximity

oPavement deterioration oMaintenance

Heavy Vehicle Impacts oLoaded water truck

o3,500 – 6,000 times the load impact of a passenger car

oRig truck o22,500 – 46,000 times the load impact of a passenger car

oEquivalent Single-Axle Load (ESAL) used in analysis

Types of Mitigation oGravel Roads

o Increased frequency of grading, gravel application, and dust suppression

oAsphalt Roads o Increased overlay frequency oDepth of pavement overlay required to offset industry impacts

oConcrete Roads o Incremental reduction in service life and expedited reconstruction

Cumulative Costs by Scenario

Scenario Development Costs

Production Costs

Total Costs

Average Annual Costs

(Range)

Scenario A $1,322,010 $166,909 $1,488,919 $148,892 ($132K – $166K)

Scenario B $525,260 $152,633 $677,893 $67,789 ($53K-85K)

Scenario C $303,780 $51,308 $355,088 $35,509 ($30K – $41K)

Costs are 10-year cumulative figures in current year dollars.

Oil and Gas Impact Fee oIsolates oil & gas impacts on City roads oDesigned to recoup the incremental city cost associated

with road damage oBased on blend of 3 scenarios; random locations and

average trip lengths oFee designed to be applied in the oil and gas land use

application process oMay require the cooperation of adjacent jurisdictions

Fee Calculation Methodology

Fees per pad and well are averaged across the three hypothetical scenarios

Oil and Gas Roadway Impact Fees Roadway Impact Fee

Per Pad $515

Per Well $4,250

Total Fees for a 12-Well Pad $51,515

Alternative fee calculation methodology: $1.17 per ESAL lane-mile

Summary oMethodology recognizes current uncertainties:

oLocation of drilling is unknown

oTraffic patterns unknown

oPace of field development uncertain

oMajor impact is accelerated road deterioration

oFees based on apportionment of expected incremental road costs per pad and per well

oFees are a tool to recover costs during period when transportation impacts are most intense—well development

Questions