HomeMy WebLinkAboutCOUNCIL - AGENDA ITEM - 04/23/2013 - REVISED - DISCUSSION OF THE OPERATING AGREEMENT BEDATE: April 23, 2013
STAFF: Laurie Kadrich, Lindsay Ex,
Dan Weinheimer
Pre-taped staff presentation: none
WORK SESSION ITEM
FORT COLLINS CITY COUNCIL
SUBJECT FOR DISCUSSION
Discussion of the Operator Agreement between the City and Prospect Energy, Inc. and the Extent
to Which Prospect Energy’s Oil and Gas Operations Should Be Exempted from the Moratorium on
Such Activities and the Ban on Hydraulic Fracturing.
EXECUTIVE SUMMARY
Council is considering whether to approve on Second Reading, an Ordinance that would exempt
Prospect Energy from a moratorium prohibiting new oil and gas drilling and a ban on the use of
hydraulic fracturing in the drilling process. Second Reading was scheduled on April 16, 2013.
After considerable discussion and public testimony, Council continued the item to April 23, 2013
to consider the issue during a work session, followed by continuation of the April 16, 2013
Adjourned Meeting. Council asked staff to provide more information regarding the inclusion of
Undeveloped Acreage (UDA) in the Operator Agreement and whether Prospect Energy would
remove the UDA from the Operator Agreement. Council also requested the following information:
• How does the Operator Agreement apply to the UDA?
• A summary of current oil and gas legislation,
• A timeline of the moratorium, ban and agreement, and
• Information regarding the existing Fort Collins Field, well locations and expansion
plans.
To be exempt from the hydraulic fracturing ban, there must be a Council-approved Operator
Agreement in place. Council stipulated Operator Agreements must ensure stringent public health
and safety measures are in place and provide strict controls on the release of methane gases and
other volatile organic compounds (VOCs). Council asked that a comparison table be developed
illustrating parts of the Agreement that exceed federal or state guidelines or regulation.
GENERAL DIRECTION SOUGHT AND SPECIFIC QUESTIONS TO BE ANSWERED
1. How does the inclusion of the Undeveloped Acreage (UDA) affect whether Council should
consider exemption Prospect Energy from the moratorium and/or the hydraulic fracturing
ban?
Option #1: If Council considers exempting Prospect Energy on Second Reading (with
the UDA) should Council act to amend the Operator Agreement to:
• Include greater set-back requirements in the UDA, and
• Prohibit any re-entry into plugged and abandoned wells in the Fort Collins
Field?
April 23, 2013 Page 2
Option #2: Should the UDA be removed from the Agreement and exemption from the
moratorium and the ban limited to the Fort Collins Field?
• If so, should the Agreement be amended to prohibit re-entry into plugged and
abandoned wells?
2. Would Council consider moving forward Land Use Code (LUC) amendments to address
reciprocal set-backs and requirement’s to identify plugged and abandoned wells prior to land
development?
3. Should staff continue with general LUC development requirements now that the ban is in
place and requires and Operator Agreement?
BACKGROUND / DISCUSSION
Oil and gas production is currently limited to the Fort Collins Field, located in the northeast portion
of the city. The Fort Collins Field is regulated by the Colorado Oil and Gas Conservation
Commission (COGCC) and has been in production since 1924. Prospect Energy has been operating
the field since 2009. In City limits, the field consists of seven oil producing wells and seven
injecting wells, all of which are managed by one operator, Prospect Energy. Prior to May 2012
Larimer County and City regulations (LUC Section 3.8.14) reference pre-emption by the COGCC
rules as the criteria for any oil and gas development within the city or county. Prospect Energy is
unable to drill new wells since Ordinance No. 145, 2012 (Moratorium) was approved December
18, 2012. In addition, the company is no longer able to utilize hydraulic fracturing since the
adoption of Ordinance No. 032, 2013. Prospect Energy also holds certain leasehold interests within
the city, described as the UDA. Absent actions taken by Council, Prospect Energy would be able
to expand operations in the Fort Collins Field and other holdings in the City and use hydraulic
fracturing under the guidelines of the COGCC.
In addition to Prospect Energy, there are 143 mineral royalty owners who are affected by whether
Prospect Energy continues oil and gas development within the city. Council allowed for exemptions
from Ordinance No. 032, 2013, provided a Council-approved operator agreement was in place that
includes strict controls on methane release and adequately protects the public health, safety and
welfare of the city. The recommended agreement with Prospect Energy contains such provisions.
A summary of those provisions follows with more detailed information contained in Attachment 5.
ANSWERS TO QUESTIONS RAISED BY COUNCIL
Would Prospect Energy remove the UDA from the Operator Agreement?
According to representatives of Prospect Energy, the company is not willing to remove the UDA
from the Operator Agreement because of the financial investment made in obtaining the lease and
the potential for significant future return on investment.
How does the Operator Agreement apply to the UDA?
All aspects of the Operator Agreement apply in the UDA, as well as those sections written
specifically for the UDA, since it is unknown what resources may be developed. Staff’s approach
April 23, 2013 Page 3
was to require Best Practices for either oil or gas production be included in the operator agreement,
especially for air and water quality, in the event that either resource is produced. For example, if
saleable amounts of gas are produced in the UDA, they must construct a sales line rather than
venting. Currently, there are no quantities of saleable gas produced in the Fort Collins Field.
More specific information is contained in the Operator Agreement regarding development of the
Fort Collins Field since there is a publicly available Surface Use Agreement in place with the
Landowner and Prospect Energy. It is important for the community that the existing Surface Use
Agreement (SUA) for the Fort Collins Field limits future development to existing well pads. There
are development limits within the SUA and Prospect Energy for the UDA; at this time only general
information is public. Prospect Energy proposes a one-thousand (1,000) foot set-back in the UDA
along the west and southern sides of the UDA in order to increase the set-back from existing and
future, potential residential development in this area. This one-thousand (1,000) foot set-back
exceeds COGCC requirements and will help further mitigate any negative impacts of development
beyond what the current Operator Agreement requires. Prospect Energy indicates that there are five
(5) potential well pads within the UDA.
Summary of current oil and gas legislation
Prospect Energy would be required to follow any current oil and gas legislation that may be enacted,
if it is more restrictive than what is already in the agreement or if it is required by law for them to
follow and not addressed in the agreement. See Attachment 2 for more information on the specific
bills.
Timeline: Moratorium, Ban and Agreement & financial impacts to Prospect Energy
According to representatives of Prospect Energy, the company was proceeding to sell the Fort
Collins Field in May 2012 when the Council on First Reading passed a moratorium against any new
oil and gas drilling. According to the company, this action resulted in a change in the regulatory
environment rating moving from “stable” to “uncertain” for the Fort Collins Field and the sale
subsequently failed. Prospect Energy has been unable to develop proved reserves in the Fort Collins
Field since a moratorium was adopted by Council. Prospect Energy reports that this change in
regulatory rating was further reduced to “unfavorable” by the adoption of a ban on hydraulic
fracturing. The combination of these actions led to a “write down of proved reserves due to
regulatory uncertainty by the Securities and Exchange Commission (SEC)” during the year end third
party evaluation. The write down reduces the amount of available capital that Prospect Energy
would have had previous to any regulations adopted by the City. See Attachment 1.
What are the environmental impacts of hydraulic fracturing? What opportunities are there to
mitigate the environmental impacts and what (mitigation approaches) are included in the
Operating Agreement?
Staff provided information to Council for consideration during the February 19, 2013 meeting as
follows:
April 23, 2013 Page 4
ENVIRONMENTAL IMPACTS
Air Quality
Several current studies pertinent to the Front Range or Rocky Mountain region were reviewed to
support the following conclusions:
• Measurable emissions of several pollutants attributable to drilling, construction, material
storage and treatment, production, and transmission activities from oil and gas operations
have been detected, including the following:
N Nitrogen oxides (NOx) and volatile organic compounds (VOCs) which are ozone
precursors
N Hazardous Air Pollutants (HAPS) including several carcinogens (primarily benzene
and formaldehyde) and other air toxics associated with chronic and sub-chronic
health effects (respiratory and neurologic disease and head, throat, and eye irritation)
N Particulate matter including dust and aerosols
N Odors (hydrogen sulfide and odiferous hydrocarbons)
N Nitrogen and sulfur compounds that contribute to visibility impairment (haze) and
atmospheric deposition
N (acid rain)
N Methane, a potent greenhouse gas and ozone precursor.
• Oil and gas development activities can emit raw (non-combusted) natural gas which has a
unique signature that can be differentiated from motor vehicle emissions and other industrial
or combustion sources. Elevated levels of volatile organic compounds associated with
natural gas operations (drilling and venting) were found in the Front Range area.
• Hydrocarbons emitted from oil and gas activities along the Front Range (primarily propane
and other alkanes) comprise some of the highly reactive precursors important in the complex
atmospheric chemistry responsible for winter ozone formation. Winter ozone formation is
a recently discovered phenomenon that has clearly been attributed to emissions from oil and
gas development and production activities in the Green River Basin (Wyoming) and Uintah
Basin (Utah).
• Associated impacts to human health including excess cancer risk and chronic non-cancer
health impacts have been measured at locations within 0.5 miles of active well pad sites.
Additional studies, many of which are currently ongoing, will help to define the potential
risk to human health, effectiveness of air emission control strategies, and potential impacts
to air quality from oil and gas development activities.
Water Quality Environmental and Health Concerns
• While there is no scientific consensus and studies are few, there is some indication of a
potential link between high-pressure underground injection (i.e., underground injection wells
for wastewater) and gas migration near the well (movement of methane into groundwater.)
The associated risk to humans is that methane that is found in drinking water sources could
potentially build up in confined spaces and cause explosions. Methane gas is not considered
April 23, 2013 Page 5
toxic if consumed in drinking water and is not regulated by the Environmental Protection
Agency (EPA) under the Safe Water Drinking Act (SWDA).
• A USGS study by Ellsworth near wastewater wells (Class II Underground Injection Control
(UIC) wells) in Menlo Park, CA suggests the high pressure injection might make well
cement cracks more likely. Findings by other researchers suggest a similar finding, but
conclude further research is needed. Although this may have implications for high pressure
injection techniques used in hydraulic fracturing, there is no scientific consensus on the
probability of its occurrence or the mechanisms involved. Local wells classified as UICs are
actually injecting at sub-fracturing pressures; see more below under earthquakes.
• Most shallow water contamination resulting from hydraulic fracturing and conventional oil
and gas production has been linked to surface activities resulting in releases of wastewater
due to accidents, poor management of wastewater storage and disposal, and illicit dumping.
• Most aquifer contamination (i.e., potential drinking water resources) from conventional oil
and gas production has been linked to well casing failures. There is not enough research for
hydraulic fracturing operations to show a similar link.
In response to public concern and industry growth, in 2009, the US House of Representatives
requested that the US EPA conduct scientific research to examine the relationship between hydraulic
fracturing and drinking water resources. The project planning phase involved agency consultation
with other federal agencies, state and interstate regulatory agencies, industry, non-governmental
organizations, and others in the private and public sector to determine the focus of the study
regarding potential impacts on human health and the environment. The primary research focused
on investigating impacts to drinking water resources. The first progress report on the results of this
research was published by the EPA, December 2012, Study of the Potential Impacts of Hydraulic
Fracturing on Drinking Water Resources, Progress Report, EPA 601/R-12/011, Office of Research
and Development. The research consists of 18 research projects and is organized around five stages
of the hydraulic fracturing water cycle:
1. Water acquisition: What are the possible impacts of large volume water withdrawals from
ground and surface waters on water resources?
2. Chemical mixing: What are the possible impacts of hydraulic fracturing fluid surface spills
on or near well pads on water resources?
3. Well injection: What are the possible impacts of the injection and fracturing process on
water resources?
4. Flowback and produced water: What are the possible impacts of both types of wastewater
surface spills on or near well pads on water resources?
5. Wastewater treatment and waste disposal: What are the possible impacts of inadequate
treatment of hydraulic fracturing wastewater on water resources?
The results from the study, which are not expected until 2014, are intended to inform the public and
provide policymakers at all levels with high-quality scientific knowledge that can be used in
decision-making. The research involves collection and analysis of existing data from 24,925 wells
that have been hydraulically fractured, complex modeling conducted by the Lawrence Berkeley
National Laboratory, toxicity assessments of 1,858 chemicals associated with hydraulic fracturing,
April 23, 2013 Page 6
and case studies. The EPA also manages the two most comprehensive databases on toxicological
data that are used for risk assessments nationally and internationally.
The literature reviews for this study are subject to a separate quality review that assesses the
soundness, applicability and utility, clarity and completeness, uncertainty and variability, and
evaluation and review of the data and information before inclusion in the research. Attachment 3
includes references accepted for inclusion in the EPA report that are organized by research topic
related to water quality. This list is a subset of references reviewed to date that cover the most
relevant research topics being investigated; for a complete list refer to the 2012 EPA report cited
above. The EPA has compiled and continues to search for literature relevant to the research
questions posed in this report including a recent Federal Register notice requesting peer-reviewed
data and publications relevant to this study. There has not been any preliminary data released from
this effort.
Waste and Wastewater Environmental Concerns
• Hydraulic fracturing produces higher volumes of wastewater that surface as flowback in a
shorter period of time than conventional drilling techniques. This creates more challenges
for capture, storage, and disposal of wastewater and associated emissions than for
conventional drilling operations (e.g., more VOC emissions if not captured adequately, more
potential for accidental spills).
• Wastewater management and disposal may be the single most important issue associated
with environmental and human health protection. The Bureau of Land Management has
proposed new requirements for submission of wastewater management plans prior to
drilling. Deep injections of wastes in Class II UIC wells, not fracturing operations, have been
linked to earthquakes to date.
Earthquake Potential in Fort Collins
Water disposal in the oil field involves injecting waste water into a deep disposal well. This process
usually increases pressure in the rock above the native state (pre-water disposal) of the rock. Usually
there is not any fluid removed from the rock, only fluid (wastewater) added, thereby increasing
reservoir pressure. Many other industries and the Federal government also use water disposal wells.
There have been noted cases of water disposal wells causing seismic activity. National Academies
of Science concluded a study in 2012 and listed three major findings:
1. “the process of hydraulic fracturing a well as presently implemented for shale gas recovery
does not pose a high risk for inducing felt seismic events;”
2. “injection for disposal of wastewater derived from energy technologies into the subsurface
does pose some risk for induced seismicity, but very few events have been documented over
the past several decades relative to the large number of disposal wells in operation”; and
3. “Carbon Capture and Storage (CCS) due to the large net volumes of injected fluids, may
have potential for inducing larger seismic.”
The factor that appears to have the most direct consequence in regard to induced seismicity is the
net fluid balance.
April 23, 2013 Page 7
The Bureau of Reclamation stated it has not done any independent studies regarding hydraulic
fracturing or deep injection wells. However, it did state that the work done between 1999 and 2004
on all the Horsetooth Dams was performed as mitigation for major seismicity that it defines as much
greater than what research reveals is a risk due to deep injection wells. Locally, a process called
waterflooding is used and, in general, operators are required to maintain pressures that are below
fracture gradient and even further lower, based on the last mechanical integrity test, according to
COGCC regulations. In other words, at the Fort Collins Field waterflooding (recycled water), the
Muddy formation maintains pressures near or slightly below original reservoir pressures.
Waterflooding started in the Fort Collins Field as a smaller pilot test in September 1979 after
obtaining COGCC approval. Upon success of the pilot, COGCC approved expansion and the
expanded project started in July 1985. According to the current operator, “We’ve been injecting
water for a long time at fairly steady rates without any recorded seismic events.”
Habitat Fragmentation Resulting From Oil and Gas Development
Several current studies pertinent to the Front Range or Rocky Mountain region were briefly
reviewed to support the following conclusions:
• Wildlife impacts and habitat fragmentation from oil and gas activities have been
documented, largely for the Greater Yellowstone and Western Wyoming regions. Species
studied include mule deer, pronghorn, and greater sage-grouse. The studies largely focused
on how migration patterns and winter habitat use could be or have been affected by oil and
gas development. Mule deer migration patterns changed in the initial year of oil and gas
development. Migration patterns did not appear to acclimate three years after well
establishment. Instead, mule deer migration patterns continued to drift further from the well
pad development areas. High value habitat areas prior to the study shifted to low habitat
values throughout the study.
A further study found that mule deer abundance for the herds in the same area had declined
by 23% during 2001-2010, where the oil and gas development had expanded.
One recent study has also examined the impact of oil and gas development on sagebrush-
dependent songbirds (Gilbert and Chalfoun 2012). Some species, which are generally more
tolerant to disturbance, such as the Horned lark (Eremophila alpestris) did not respond to
increases in well densities. However other species, such as the Brewer’s sparrow (Spizella
breweri) and sage sparrow (Amphispiza belli) which are dependent on sagebrush
communities, had significant population decreases as oil and gas well density increased,
suggesting there may be significant impacts to sagebrush-obligate species. A comprehensive
synthesis of oil and gas impacts was recently compiled by The Wildlife Society in 2012. In
addition to the issues addressed above, the report also identifies increased noxious weed
invasions, impacts to waterfowl from wetland impacts, and the potential for increased
competition between deer and elk as highly valued habitat is used for oil and gas
development. The report also highlights that the cumulative effects of habitat fragmentation,
overall loss, and degradation may prove to have the most impact on wildlife.
• Horizontal drilling may reduce the overall impacts of habitat fragmentation, as multiple
areas of land can be accessed from a single well pad. However, it is difficult to know the
extent of this reduction without further study.
April 23, 2013 Page 8
• Based on the studies available, habitat fragmentation effects from oil and gas development
appear to be better understood at the landscape level, e.g., how oil and gas development
affects pronghorn and mule deer migration patterns. Thus, the findings from these studies
may be best applied at the regional scale, e.g.,Larimer County and the Rocky Mountain
Foothills.
• Staff did not find any research that compared the habitat fragmentation effects of oil and gas
development in rural or open undeveloped lands with those in more traditional urban
development.
Mitigation measures are proposed by staff and included in the Operator Agreement – see Attachment
3 for some of the measures included specific to hydraulic fracturing. Another significant measure
is a requirement in the Agreement that the Operator must have twenty-four (24) hour supervision
on site for any new drilling.
Information regarding the existing Fort Collins Field, well locations and expansion plans
Level of oversight: Since 2009, the COGCC inspected the Fort Collins Field at least 142 times.
There are no known safety concerns with existing wells. Existing wells would continue to have
oversight by the COGCC. Any new wells must conform to all COGCC regulations in addition to
any Best Management Practices contained in the Operator Agreement.
Count of pads and wellheads in the existing field: There are currently fifteen (15) wells in the City
limits; seven (7) of those produce oil, the remaining are water re-injection wells. It is not certain
which wells pads will be regulated by the Agreement or which will remain as “existing” (see
Attachment 6 for possible locations). Prospect Energy has indicated which well pads are likely to
be added to, however a proposed new development may affect any new well locations. It is
estimated that two (2) or three (3) well pads may be used for new wells and the remaining four (4)
or five (5) would remain as is. An additional six (6) to eight (8) additional wells are possible in City
limits of the Fort Collins Field.
Why can’t the Best Management Practices listed in the Agreement be applied to all wells in the
City?
Generally, new requirements apply to new development so the proposed agreement limited any new
conditions and/or requirements to any new development.
What is the difference between the existing field and the UDA?
The primary difference is that the existing field has been in oil production since 1924 and while
exploration has occurred in the UDA, neither oil or gas production has followed. There is however,
current production both east and west of the UDA so there is some likelihood of either oil or gas
resources (or both) being present. Another key difference is that any development in the UDA must
occur under City jurisdiction rather than County since the UDA is already in the City. All
development in the existing field was annexed into the City.
Will the Operator voluntarily provide sniffers to neighbors of the well sites so they can monitor
air quality?
April 23, 2013 Page 9
Providing sniffers to neighbors could provide numerous benefits to nearby neighbors, such as early
detection of hydrogen sulfide and Volatile Organic Compounds (VOCs). As health concerns are
more often related to VOCs, it may be best to focus on early detection of VOCs. However,
monitoring and measuring VOCs require more technically rigorous protocols. For example, citizens
would need to be trained in the equipment, a standard methodology would need to be established,
ideally citizen “teams” would be established so quality assurance would increase, and re-training
on at least an annual basis would be recommended. This type of Citizen Science effort may lend
itself to be better managed by the City or by the Larimer County Department of Health, which could
better manage the data over a longer time period. Because of the required rigor associated with
monitoring VOCs, it may prove a liability for the Operator to manage. Staff is not aware of a case
where an operator has wanted to take on such liability.
Comparison table illustrating parts of the Agreement that exceed Federal or State guidelines or
regulation
Staff focused on key air and water quality measures contained in the Operator Agreement for
illustration purposes as to how they meet or exceed State and Federal regulations or guidelines. The
commitment to provide a minimum of a one-thousand (1,000) foot set-back along the south and
western boundaries of the UDA exceeds existing state set-back regulations. Prospect Energy has
previously described their operations as exceeding current state or federal regulations by installing
a thermal oxidizer, disclosing chemicals, conducting neighborhood meetings, installing vapor
recover, using camera technology for leak detection, conducting an hydrogen sulfide survey of
operations which led to a wet-land being the source of odors rather than the company. All technical
staff members were asked to confirm that the areas proposed by their respective disciplines met or
exceeded current regulatory guidelines. See Attachment 3.
If Federal or State regulations are less than what is required in the Agreement, which prevails?
The Operator agreement specifies that whatever measure is “more stringent” (Appendix A, #1) is
what applies, so if the Agreement is more stringent it applies.
If the City and Larimer County agree that any oil and gas development in the Growth
Management Area requires annexation to the City, will the terms and conditions of the
Agreement apply to those areas?
Yes. Language contained in Section #3 of the Agreement requires that, at such time, if at all, the
City and County enter into a written agreement that authorized the City to regulate,” such
operations will be governed by the Agreement.
ATTACHMENTS
1. Project timeline
2. Current Legislation
3. Comparison Table Operator Agreement BMPs vs. Federal & State
4. Powerpoint Presentation
5. March 19, 2013 Agenda Item Summary - Memorandum of Understanding (MOU) with
Prospect Energy, w/o attachments
April 23, 2013 Page 10
6. Prospect Energy’s Fort Collins Field Well locations
7. Comparison Table Operator Agreement BMPs vs. COGCC.
Attachment #1
Oil and Gas Operations - Project Timeline – Updated April 19, 2013
Issue 2012 2013
May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr
Moratorium
Hydraulic Fracturing Ban
Operator Agreement
Notes
Prior to May 2012:
Larimer County and City
rules reference pre-emption
by the COGCC rules (see
Section 3.8.14 of the Land
Use Code)
Moratorium:
1st Reading
5/15/12
(6-0 vote)
2nd Reading
6/5/12
(3-3 vote)
Council Work
Session: 6/12/12
Summer and fall 2012: Advisory Committee
meetings, Planning and Zoning Board
recommends adoption of Land Use Code
regulations (11/15/12)
In December, staff presented Council with
three options, including two Land Use Code
regulatory options and the moratorium.
A six-month moratorium passes on 1st Reading
12/4/12 (6-0 vote)
A seven-month moratorium adopted on
second reading (6-0 vote, 12/18/12), expires
07/31/13.
Hydraulic
Fracturing Ban:
1st Reading
2/19/13
(5-2 vote)
On 3/1/13,
staff first
meets with
Prospect
Energy to
develop an
Operator
Agreement
Hydraulic fracturing
ban (City Code
Sections 12-135, 12-
136) is adopted on
second reading
(5-2 vote, 3/5/13).
Operator Agreement
adopted by
Resolution 3/19/13
(4-2 vote).
1st Reading to
exempt Prospect
1
Oil and Gas‐related bills 2013
SB13‐202
ADDITIONAL INSPECTIONS AT OIL & GAS FACILITIES
The bill requires the Colorado Oil and Gas Conservation Commission (COGCC) in the
Department of Natural Resources (DNR) to report to the Joint Budget Committee and
House and Senate committees of reference with jurisdiction over energy by February 1,
2014, on utilizing a risk‐based strategy for inspecting oil and gas locations that targets
operational phases that are most likely to experience spills, excess emissions, and other
types of violations.
The report is to include findings, recommendations, and a plan, including staffing and
equipment needs for implementing the strategy.
The bill requires implementation of a strategy by July 1, 2014, which may include a pilot
project to test the strategy. The reporting requirement is repealed September 1, 2014.
SB13‐275
CONCERNING THE CREATION OF AN INTERIM COMMITTEE OF THE GENERAL ASSEMBLY TO
REVIEW MATTERS RELATING TO PIPELINE SAFETY
The bill creates a legislative interim committee to address oil and gas pipeline safety and
to review and propose bills on that topic.
The Pipeline Safety Review Committee must convene stakeholders, request briefings
from regulatory agencies and information from other sources, make determinations,
and consider other issues.
It is authorized to meet up to 6 times during the interim; consult with experts, including
state personnel; and propose up to 3 bills.
HB13‐1267
CONCERNING INCREASED PENALTIES FOR VIOLATIONS BY OIL AND GAS OPERATORS
Current law specifies that a violation of the "Oil and Gas Conservation Act" is punishable
by a maximum fine of $1,000 per day, subject to a penalty schedule promulgated by the
oil and gas conservation commission that considers aggravating and mitigating
circumstances.
The maximum total fine is capped at $10,000 for violations that are not significant.
The bill increases the maximum daily fine to $15,000, sets a minimum fine of $5,000 per
violation per day for violations that have a significant adverse impact on public health,
safety, or welfare, including the environment and wildlife resources, and repeals the cap
on the maximum total fine.
HB13‐1268
CONCERNING A DISCLOSURE OF POSSIBLE SEPARATE OWNERSHIP OF THE MINERAL ESTATE IN
THE SALE OF REAL PROPERTY
The bill requires a seller to disclose in the sale of real property that a separate mineral
estate may subject the property to oil, gas, or mineral extraction. A standard disclosure
ATTACHMENT 2
2
or a substantially similar disclosure is required. A seller that provides this disclosure is
not liable for any damages of the purchaser from oil, gas, or mineral extraction.
Would apply to contracts entered into on or after January 1, 2014.
HB13‐1269
CONCERNING THE REDUCTION OF CONFLICTS OF INTEREST WITHIN THE COLORADO OIL AND
GAS CONSERVATION COMMISSION
Section 1 of the bill amends the commission's mandate to ensure that the development
of oil and gas resources protects public health, the environment, and wildlife resources.
Section 2 redefines "waste" to exclude reduced production that results from compliance
with government regulation.
Section 3 requires an annual disclosure on a public website by each commissioner the
identity of each operator and oil and gas service company of which the commissioner is
an employee, officer, or director or in which the commissioner has a direct or
substantial financial interest; the nature of the commissioner's direct or substantial
financial interest and position with each such operator or oil and gas service company
and the commissioner's duties in connection with the position; and a listing of each such
operator's or oil and gas service company's business interests in Colorado.
HB13‐1273
CONCERNING NEW FUNDING LOCAL GOVERNMENTS OIL AND GAS DEVELOPMENT IMPACTS
Bill requires operators to pay a local government designee fee to the Colorado Oil and
Gas Conservation Commission (COGCC) when applying for a permit to drill.
The COGCC will allocate the fee equally to each local government that has a registered
local government designee within whose boundaries the oil and gas facility to be
permitted is located.
The bill allows local governments to collect an impact fee or development charge when
issuing a development permit to offset the costs for environmental or public health and
welfare oversight on new oil and gas development.
The bill also repeals the prohibition on local governments charging a tax or fee for
conducting inspections or monitoring of oil and gas operations.
HB13‐1275 ‐ FAILED
CONCERNING A FRONT RANGE OIL AND GAS HUMAN HEALTH STUDY
Requires the State Board of Health (board), in the Department of Public Health and
Environment (DPHE), to issue a request for proposals (RFP) to conduct a review of
existing epidemiological data to determine whether oil and gas operations can have an
adverse effect on human health.
The selected contractor's final report, which must be prepared in consultation with the
oversight committee created in the bill, is due by March 15, 2014.
The review is to be based on data collected in or near Larimer, Weld, Boulder, and
Arapahoe counties and is to include at least one control area. The contractor is required
3
to design the review with input from medical researchers, statisticians, and
environmentalists to provide scientifically‐based information, including:
• acute, chronic, debilitating, fatal, and transgenerational conditions of the general
population and certain at‐risk populations; and
• an analysis of existing incidence data for an appropriate period of time before and
after the commencement of oil and gas operations in each particular geographic area.
The review may include a finding regarding whether the Division of Administration or
the Water Quality Division in the DPHE, or the Colorado Oil and Gas Conservation
Commission (COGCC) in the Department of Natural Resources, should exercise their
power to issue a cease‐and‐desist order for specific oil and gas facilities.
The oversight committee is comprised of 11 members. Appointees who are not
legislators must be physicians or have experience in occupational or public health,
epidemiology, biomedical science, or statistics. Appointments must be made by July 1,
2013, and are made as follows:
• the President of the Senate and Speaker of the House each make three appointments,
including one legislator from each house;
• the minority leaders of each house make two appointments; and
• the Governor appoints one member to represent DPHE
HB13‐1278
CONCERNING OIL SPILLS GAS RELEASES REPORTING
The bill requires that spills of oil or exploration and production waste of one barrel (42
U.S. gallons) that is spilled outside of berms or other secondary containment
mechanisms be reported within 24 hours of discovery to both the Colorado Oil and Gas
Commission (COGCC) and the local jurisdiction responsible for emergency response.
The spill must be reported to the Colorado Oil and Gas Commission (COGCC), the local
jurisdiction responsible for emergency response, the surface owner, and owners of land
adjacent to the spill.
The COGCC may promulgate rules to implement these requirements.
HB13‐1316
OIL GAS COMMISSION UNIFORM GROUNDWATER SAMPLE RULE
Bill requires the COGCC to adopt a uniform standard groundwater monitoring rule for
the entire state.
Attachment #3
Note – within the table, the section of the Operator Agreement is referenced in parentheses, e.g., (Appendix B) Develop Water Quality
Monitoring Plan indicates that the standard can be found in Appendix B.
Oil and Gas Operations
Comparison Table – Selected Sections of the Operator Agreement compared with Federal and State Regulations
Updated April 22, 2013
Operator Agreement Water Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
1. (Appendix B) Develop
water quality monitoring
plan
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
Water quality monitoring plan required
2. (27) Sample “Available
Water Sources”
No equivalent
regulation
Water wells registered with CO Division of
Water Resources preferred,
Also allows permitted or adjudicated
springs or monitoring wells
Same requirements as COGCC
3. (27) Number of water
sources sampled
No equivalent
regulation
Cap of 4 water sources Same requirements as COGCC
4. (27) Location of water
sources sampled
No equivalent
regulation
Located within ½ mile radius of proposed
well
Same requirements as COGCC
5. (27) Orientation of
sampling locations
No equivalent
regulation
Both up‐gradient and down‐gradient
sampling required
Same requirements as COGCC
6. (27) Multiple identified
aquifers
No equivalent
regulation
Sampling of multiple defined aquifers (e.g.,
deepest and shallowest)
Same requirements as COGCC
7. (27) Timing of sampling No equivalent
regulation
1 baseline sampling event prior to site
construction
2 post‐completion sampling events (one
between 6 and 12 months after and one
between 60 and 72 months after)
Operator Agreement is more stringent
Attachment #3
Operator Agreement Water Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
8. (27) Sampling procedures
and analysis
No equivalent
regulation
Baseline sampling for drinking water
analytes, dissolved and gaseous petroleum
hydrocarbons, and microbiological
parameters
Post‐completion sampling for same
parameters as baseline sampling
Additional stable isotope analysis of
methane performed if thresholds for
methane exceeded
Operator Agreement is more stringent
Same parameters for baseline and post‐
completion sampling are tested
Same tests using stable isotope analysis
required
Added new requirement for testing
dissolved metals
9. (39) Soil gas monitoring No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
Added requirement that may be used to
assess well casing integrity and potential
for methane gas migration
Operator Agreement Air Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
1. (21.a) – General Duty to
Minimize Emissions
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
2. (21.b) – HLP‐VRU on new
wells in the UDA
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent –
note that this is the same as operator
agreement in the region (not limited to
City limits)
2
Attachment #3
Comparison Table – Operator Agreement vs. State and Federal Regulations
Operator Agreement Air Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
3. (21.d) No uncontrolled
venting of methane
40 CFR Part 60
Subpart
OOOO with
exceptions for
safety and
feasibility
CDPHE Regulation No. 6 Part A Operator Agreement is more stringent
Requirement applies regardless of well
type.
4. (21.d) All gas vapors shall
be captured to the extent
feasible
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
5. (21.d) Vapor capture
equipment shall operator
at 98% efficiency or
greater
40 CFR Part 60
Subpart
OOOO
requires 95%
on some
equipment at
natural gas
wells
CDPHE Rule 805.b(2) and CDPHE Reg. 7
XVIIB.1 – requires 90‐95% control
depending on equipment type and
uncontrolled emissions
Operator Agreement is more stringent
6. (21.e) Capture and
beneficial use of natural
gas is preferred over
flaring
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
7. (21.e) Flaring shall be
continuously monitored
40 CFR
60.18(f)
No equivalent regulation Operator Agreement is more stringent
8. (21.e) No venting of gas
may occur except under
COGCC rule 805(B)(3)(b) or
rule 912
No equivalent
regulation
COGCC Rule 805 and Rule 912 allow
venting for safety and emergencies
Attachment #3
Operator Agreement Air Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
9. (21.f.1) Flare shall be
operated with natural gas
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
10. (21.f.1) Flare shall be
operated with 98% or high
Volatile Organic
Compound (VOC)
destruction efficiency (DE)
40 CFR Part 60
Subpart
OOOO
requires 95%
on some
equipment at
natural gas
wells.
COGCC requires 90‐95% control required
depending on the source
Operator Agreement is more stringent
11. (21.f.2) Flare shall be
designed and operated in
compliance with 40 CFR
60.18(f) and CDPHE Reg. 7
Section XVIIB
Complies with
EPA Federal
regulation
Complies with CDPHE regulation Same requirements as state and federal
regulations
12. (21.f.3) The flare shall be
operated with a flame
present at all times when
emissions may be vented
to it, pursuant to the
methods specified in 40
CFR 60.18(f).
Complies with
EPA Federal
regulation 40
CFR 60.18
Complies with CDPHE Reg. 7 Section
XVII.B.1.c
Same requirements as state and federal
regulations
4
Attachment #3
Comparison Table – Operator Agreement vs. State and Federal Regulations
Operator Agreement Air Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
13. (21.f.4) An automatic pilot
system shall be used when
feasible. Other ignition
systems may include the
installation and operation
of a telemetry alarm
system or an on‐site
visible indicator showing
proper function.
No equivalent
regulation
CDPHE Reg. 7 Section XVII.B.1.c requires no
visible emissions and observation of proper
function; similar to current language and
includes proposed changes to Reg. 7
Operator Agreement is more stringent
14. (21.g) The Company shall
develop and maintain a
leak detection and
component repair
program according to EPA
Method 21 for equipment
used in permanent
operations. LDAR shall be
performed on newly
installed equipment, and
then on an annual basis.
EPA 40 CFR
Part Subpart
Vva – LDAR
Requirements
for several
industries that
emit VOCs
COGCC Rule 604.c.(2).f – leak detection
plan required if within designated setback
location
Operator Agreement is equivalent or
more stringent
Operator Agreement language is similar
to EPA requirement; VOC leaks from
equipment similar to COGCC rule, and
applies regardless of location.
5
Attachment #3
Operator Agreement Air Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
15. (21.g) A Forward‐Looking
Infrared (FLIR) camera
shall be used as the
preferred implementation
method of EPA Method 21
as available from the
state; if unavailable, other
methods shall be used in
compliance with this
method.
EPA Method
21 40 – CFR
Part 60,
Appendix A‐7
and 40 CFR
60.18(g)
(FLIR camera
is an
alternative
compliance
method
accepted by
EPA
COGCC Rule 604.c.(2).f ‐ leak detection plan
required if within designated setback
location.
Operator Agreement is more stringent
because this requirement applies to all
types of development and regardless of
location.
16. (21.g) Upon request from
the City, the Company
shall implement EPA
Method 21 upon
additional concerns
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
17. (21.g) At least once per
year, the Company shall
notify the City prior to FLIR
camera use in case the
City wishes to observe the
method
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
18. (21.h) One Time Baseline
Air Quality Monitoring
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
6
Attachment #3
Comparison Table – Operator Agreement vs. State and Federal Regulations
Operator Agreement Air Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
19. (21.i) One Time Air
Sampling During Well
Completion
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
20. (21.j) Ongoing Air Quality
Monitoring
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
21. (21.k) The City may require
the Company to conduct
additional air monitoring
as needed to respond to
emergency events such as
spill, process upsets, or
accidental releases or in
response to odor
complaints in City Limits
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
22. (21.l) Air Quality Action
Days – requires operator
to develop temporary
response actions to poor
quality air days
No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
7
Attachment #3
Operator Agreement Air Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
23. (22.a) Green Completions
Gas gathering lines,
separators, and sand traps
capable of supporting
green completions as
described in COGCC Rule
805 shall be installed at
any location at which
commercial quantities of
gas are reasonably
expected to be produced
based on existing adjacent
wells within one (1) mile
or well in the Fort Collins
Field, whichever is greater.
40 CFR Part 60
Subpart
OOOO for
natural gas
wells
COGCC 604.c.(2).c and COGCC 805.b(3) –
same requirements for wells located within
a Designated Setback Location, effective
August 2013
Operator Agreement is equivalent or
more stringent
Operator Agreement language requires
green completions regardless of where
well is located and where viable
quantities of gas are produced.
24. (22.b) Uncontrolled
venting is prohibited
40 CFR Part 60
Subpart
OOOO for
natural gas
wells,
exceptions for
safety and
feasibility
COGCC 604.c.(2).c – same requirements as
for wells located within a Designated
Setback Location effective August 2013
Operator Agreement is equivalent or
more stringent
Operator Agreement language prohibits
uncontrolled venting regardless of
where well is located.
8
Attachment #3
Comparison Table – Operator Agreement vs. State and Federal Regulations
Operator Agreement Air Quality Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
25. (22.c.1‐4) Temporary
flowback flaring and
oxidizing equipment shall
include the following
elements (see Operator
Agreement)
40 CFR Part 60
Subpart
OOOO for
natural gas
wells,
specifies
similar or
equivalent
equipment for
reduced
emission
completions.
COGCC 604.c.(2).c – same requirements as
for wells located within a Designated
Setback Location effective August 2013
Operator Agreement is equivalent or
more stringent
Operator Agreement language requires
specific equipment regardless of where
well is located and where feasible.
9
Attachment #3
Operator Agreement Notification and Inspection Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
26. (3) Conceptual Review No equivalent
regulation
No equivalent regulation; Local
Government Designee can elect to be
notified
(Rule 306.b) Local governments that have
appointed a local governmental designee
(LGD) shall be given an opportunity to
engage in such consultation concerning an
application for Permit‐to‐Drill, Form 2, or
an Oil and Gas Location Assessment, Form
2A, for the location of roads, production
facilities and well sites prior to the
commencing of operations with heavy
equipment.
Operator Agreement is equivalent or
more stringent
Added requirement ‐ Requires City be
notified 30 days prior to submittal of an
Application for a Permit to Drill
27. (4) Mailed Notice No equivalent
regulation
(Rule 305.a) Pre‐application notifications.
For Oil and Gas Locations proposed within
an Urban Mitigation Area or within the
Buffer Zone Setback, an Operator shall
provide a “Notice of Intent to Conduct Oil
and Gas Operations” to surface owners,
owners of all Building Units within the
Exception Zone Setback, and owners of
surface property within five hundred (500)
feet of the proposed Oil and Gas Location,
not less than thirty (30) days prior to
submitting a Form 2A Oil and Gas Location
Assessment to the Director.
Operator Agreement is more stringent
Added requirement to notify (in
addition to surface owners) that any
surface owner, regardless of whether a
building is present, within ½ mile shall be
notified; any surface owner within 500’
of a proposed gathering line shall be
notified, and that any person registered
as a neighborhood group or organization
shall also be notified
10
Attachment #3
Comparison Table – Operator Agreement vs. State and Federal Regulations
Operator Agreement Notification and Inspection Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
28. (5) Posted Notice No equivalent
regulation
No equivalent regulation Operator Agreement is more stringent
Added requirement to post sign in
similar manner as to other development
review applications
29. (6) Neighborhood
Meetings
No equivalent
regulation
(Rule 305) Operators must engage in
expanded notice and outreach efforts with
nearby residents and conduct additional
engagement with local governments about
proposed operations. As part of this,
operators proposing drilling within 1,000 feet
must meet with anyone within that area who
asks.
Operator Agreement is more stringent
Added requirement that neighborhood
meetings must be conducted in
accordance with existing City standards
30. (7) Notification to the City
and the public regarding
commencement of
operations
No equivalent
regulation
(Rule 912.e) Operators shall notify the local
emergency dispatch or the local
governmental designee of any natural gas
flaring. Notice shall be given prior to flaring
when flaring can be reasonably anticipated,
or as soon as possible, but in no event
more than two (2) hours after the flaring
occurs.
Operator Agreement is more stringent
Added requirement that any
commencement, not just for flaring,
requires notification
11
Attachment #3
Operator Agreement Notification and Inspection Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
31. (8) Inspections No equivalent
regulation
COGCC maintains an Onsite Inspection
Policy (last updated December 2005) that
governs protocol for inspections related to
permit approval. Onsite inspections may be
requested under Rule 306. The purpose of
the onsite inspection shall be to determine
whether technical or operational conditions
of approval should be attached to the APD
in order to:
1. Avoid potential unreasonable crop loss
or land damage;
2. Address potential health, safety and
welfare or significant adverse
environmental impacts within COGCC
jurisdiction regarding the proposed surface
location that may not be adequately
addressed by COGCC rules or orders, or
3. Otherwise ensure compliance with the
COGCC’s rules relating to advance notice
and good faith consultation with respect to
timing of operations and location of
facilities.
Operator Agreement is more stringent
Added requirement that City can inspect
at any time, with 24 hours advanced
notice (see also Emergency Response
section)
12
Attachment #3
Comparison Table – Operator Agreement vs. State and Federal Regulations
Operator Agreement Setback Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
32. (2) Setbacks required for
new wells
No equivalent
regulation
Statewide uniform setback – 500’ from
building units; 1,000’ from institutional
buildings
If proposing to construct a well within
1,000 feet of an occupied structure, the
operators are required to meet new and
enhanced measures to limit the disruptions
a nearby drill site can create. Those
measures include closed loop drilling that
eliminate pits, liner standards to protect
against spills, capture of gases to reduce
odors and emissions, as well as strict
controls on the nuisance impacts of noise,
dust and lighting.
Operator Agreement is more stringent
Added requirement that a minimum
setback of 1,000’ be applied in the
Undeveloped Acreage (UDA) on the
south and western borders to increase
the setbacks from any existing or
proposed residential development
Operator Agreement Waste Management and Disposal Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
33. (9) Containment berms Exempted
under RCRA
for E&P
wastes
Rule 906 requires secondary containment
with liquids >3,500 total dissolved solids.
Rule does not apply to water tanks < 50
barrels
Operator Agreement is more stringent
Required for all tanks and separators at
new well pads
Must be lined
Additional containment required within
500 feet up‐gradient of surface water
34. (10) Pitless systems Pits allowed
under RCRA
Pits allowed under Rule 902 Operator Agreement is more stringent
No pits allowed
35. (14) Onsite storage of Allowed Allowed under 900 series Rules Operator Agreement is more stringent
13
Attachment #3
wastes under RCRA No long‐term storage allowed
36. (18) Use of produced
water for dust suppression
Allowed
under E&P
RCRA
Exemption
Allowed under 900 series Rules Operator Agreement is more stringent
Not allowed
37. (45) Land treatment or
disposal of drilling muds
Allowed
under E&P
RCRA
Exemption
Allowed under 900 series Rules Operator Agreement is more stringent
Not allowed
38. (45) Spill Prevention,
Control, and
Countermeasure Plan
(SPCC)
None for this
size facility
Not required for a facility of this size Copy of Operator Company‐level SPCC
provided to Director, similar to State
regulations
Operator Agreement Chemical Disclosure Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
39. (14) Chemical Disclosure
and Storage
No equivalent
regulation
Website fracfocus.org was developed by
the Ground Water Protection Council and
the Interstate Oil and Gas Compact
Commission. Operators must utilize registry
to post information. (See Rule 205)
Operator Agreement is more stringent
Added requirement to also provide the
information on chemicals to the City;
also does not allow any chemicals to be
permanently stored on the site.
Operator Agreement Emergency Response Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
40. (20) Emergency
preparedness plan
Numerous
federal
agencies
It is our understanding that similar
standards that are used at the federal level
are employed at the State level
Same requirements as state and federal
regulations, as well as the adopted
Boulder County and Loveland
Attachment #3
Comparison Table – Operator Agreement vs. State and Federal Regulations
oversee
emergency
response
issues; they
have similar
standards to
what is
proposed
Staff also looked to the International Fire
Code, International Building Code, and
other state and federal regulations to
develop these standards
regulations
Operator Agreement Natural Resources Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
41. (32) Natural Resources –
requires compliance with
Section 3.4.1 of the Land
Use Code
Must comply
with
Endangered
Species Act
and other
federal
regulations
(Rule 1201 and 1203) – The state requires
certain regulations for operating within
sensitive natural areas, all of which would
apply to Prospect Energy, e.g., the
requirement to install wildlife crossovers if
open trenches are left open for more than
5 days and are greater than 5’ in width, can
also trigger consultation with the Division
of Parks and Wildlife.
Operator Agreement is more stringent
Added requirement to require that all
natural habitats and features as
identified by the City be accounted for,
protected, as if necessary, mitigated in
the site analysis and design; not just the
resources outlined by the state, e.g.,
winter migration corridors for mule
deer, bald eagle nests, etc.
Operator Agreement Noise Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
42. (33) Noise mitigation No equivalent
regulation
known to staff
(Rule 802) The type of land use of the
surrounding area shall be determined by
the Director in consultation with the Local
Governmental Designee taking into
Operator Agreement is more stringent
Attachment #3
Operator Agreement Noise Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
consideration any applicable zoning or
other local land use designation. In the
hours between 7:00 a.m. and the next 7:00
p.m. the noise levels permitted above may
be increased ten (10) dB(A) for a period not
to exceed fifteen (15) minutes in any one
(1) hour period. The allowable noise level
for periodic, impulsive or shrill noises is
reduced by five (5) dB (A) from the levels
shown.
ZONE 7:00 am to
next 7:00 pm
7:00 pm
to next
7:00 am
Residential/
Agricultural/Rural
55 db(A) 50 db(A)
Commercial 60 db(A) 55 db(A)
Light industrial 70 db(A) 65 db(A)
Industrial 80 db(A) 75 db(A)
(Rule 802.e) Exhaust from all engines,
motors, coolers and other mechanized
equipment shall be vented in a direction
away from all building units.
with State regulations will be achieved;
also requires noise mitigation measures
to be constructed whenever the
operation is at the edge of either an
existing residential development or area
zoned for future residential
development.
43. (19) Electric equipment No equivalent
regulation
(Rule 802.f) All Oil and Gas Facilities with
engines or motors which are not electrically
Operator agreement is similar to state
regulations; the City stresses the use of
16
Attachment #3
Comparison Table – Operator Agreement vs. State and Federal Regulations
Operator Agreement Noise Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
known to staff operated that are within four hundred
(400) feet of Building Units shall be
equipped with quiet design mufflers or
equivalent. All mufflers shall be properly
installed and maintained in proper working
order.
Electric Equipment at all sites; the state
specifies a certain distance at which
additional measures must be taken.
Operator Agreement Transportation and Circulation Requirements
Operator Agreement
Requirement
Federal State/COGCC Comparison
44. (44) Transportation and
Circulation
No equivalent
regulation
known to staff
(Rule 334) All persons subject to the COGCC
rules and regulations while using public
highways or roads shall be subject to the
State Vehicles and Traffic Laws pursuant to
Title 42, C.R.S. and the State Highway and
Roads Laws, Title 43, C.R.S., pertaining to
the use of public highways or roads within
the state.
(Rule 604.c.2.d) Traffic Plan. If required by
the local government, a traffic plan shall be
coordinated with the local jurisdiction prior
to commencement of move in and rig up.
Any subsequent modification to the traffic
plan must be coordinated with the local
jurisdiction.
Operator Agreement is more stringent
Added requirement that a
Transportation Impact Analysis be
submitted to the City during the
Conceptual Review of the project; also
requires proposed traffic and access
routes as well as a bond to cover any
damage that occurred during the well
drilling and completion phase of the site.
17
ATTACHMENT 4
Attachment 4 (staff powerpoint presentation)
will be available later today (April 23).
COPY
COPY
COPY
ATTACHMENT 5
DATE: March 19, 2013
STAFF: Laurie Kadrich, Lindsay Ex
Dan Weinheimer
AGENDA ITEM SUMMARY
FORT COLLINS CITY COUNCIL 28
SUBJECT
Items Relating to an Operator Agreement between the City and Prospect Energy, LLC.
A. Resolution 2013-024 Approving an Oil and Gas Operator Agreement Between the City and Prospect Energy,
LLC.
B. First Reading of Ordinance No. 057, 2013, Terminating the Moratorium Imposed by Ordinance No. 145, 2012
with Respect to Oil and Gas Operations Conducted under an Oil and Gas Operator Agreement Between the
City and Prospect Energy, LLC.
EXECUTIVE SUMMARY
Council is considering the approval an Operator’s Agreement with Prospect Energy that would permit Prospect Energy
to conduct oil and gas operations in the city limits. The terms of the Agreement ensure stringent public health and
safety measures are in place through Best Management Practices (BMPs),which generally exceed current
requirements mandated by the Colorado Oil and Gas Conservation Commission (COGCC), and provide strict controls
on the release of methane gases and other volatile organic compounds (VOCs). If the Agreement is approved,
Council will consider adopting Ordinance No. 057, 2013 removing the Moratorium imposed by Ordinance No. 145,
2012 with respect to an Oil and Gas Operator Agreement with Prospect Energy.
BACKGROUND / DISCUSSION
Oil and gas production is currently limited to the Fort Collins Field (Attachment #2), located in the northeast portion
of the city. The Fort Collins Field is regulated by the COGCC and has been in production since about 1925. In the city
limits, the field consists of seven oil producing wells and seven injecting wells, all of which are managed by one
operator, Prospect Energy. Prospect Energy is unable to drill new wells since Ordinance No. 145 (Moratorium) was
approved December, 2012. In addition, the company is no longer able to utilize hydraulic fracturing since the adoption
of Ordinance No. 032. Prospect Energy also holds certain leasehold interests within the City described as the
Undeveloped Area (UDA), as depicted in Attachment #2. Council allowed for exemptions from Ordinance No. 032
provided a Council approved operator agreement was in place that includes strict controls on methane release and
adequately protects the public health, safety and welfare of the city. The recommended agreement with Prospect
Energy contains such provisions. A summary of those provisions follows with more detailed information contained
in Exhibit A to Resolution 2013-024.
Summary of Controls for Methane Gas
Prospect Energy captures all gases from production and tanks and routes them to a thermal oxidizer for destruction.
This method currently results in over 99% of all emissions being destroyed. The COGCC rule requires 95% of
emissions be destroyed. This proposed Agreement requires at least 98% destruction and use of a thermo-oxidizer
for emission destruction to be utilized for any new wells in the Fort Collins Field. In the UDA, Prospect Energy will
capture and destroy emissions at the well (Exhibit A -Section 21 (b)) or send through a thermal oxidizer. Prospect
Energy also agrees to comply with:
• Environmental Protection Agency (EPA) Method 21 (Section 21 – Exhibit A)
• No uncontrolled venting of methane (Section 21 – Exhibit A)
• Minimal flaring during drilling and completions (Section 21 – Exhibit A)
• Develop and maintain a Leak Detection and Repair (LDAR) (Section 21 – Exhibit A)
N Use a Forward-Looking Infrared (FLIR) camera
N Notify the City for observation of testing
• Green Completions (Section 22- Exhibit A)
COPY
COPY
COPY
March 19, 2013 -2- ITEM 28
• Containment of all produced water or flowback fluids and no permanent storage of waste products (Section
45 – Exhibit A)
Summary of Best Management Practices
(Public Health and Safety Measures – details in Exhibit A)
Setbacks – Any new wells drilled will conform to the current COGCC rules which will be five hundred (500) feet from
any building and one thousand (1,000) feet from any institutional facility beginning August 1, 2013. However, in the
Fort Collins Field, new wells must be constructed on existing well pads because of an existing Surface Use Agreement
(SUA), which conform to previous COGCC setbacks. Those well pads are located near or within Water’s Edge,
Richard’s Lake and Hearthfire subdivisions.
Conceptual Review – No less than thirty (30) days prior to the submission of an Application for a Permit to Drill (APD)
(note: APD is the COGCC permitting process), Prospect Energy will schedule a meeting with the City to review the
proposed new well or drilling activity. The goal of this meeting would be for staff and the applicant to review the
proposed oil and gas operation in a manner that ensures compliance with the operator agreement and applicable state
and federal regulations. This pre-submittal meeting will also allow the applicant and staff to explore site-specific
concerns, to discuss project impacts and potential mitigation methods including field design and infrastructure
construction to minimize impacts, to discuss coordination of field design with other existing or potential development
and operators, to identify sampling and monitoring plans for air and water quality, and other elements of the operator
agreement as contained in Exhibit A.
Community Notice –Prospect Energy must provide community and staff notice. Prior to an APD, the Agreement
specifies mailed notice, posted notice, neighborhood meetings and also a notification to the public prior to the
commencement of drilling. Consistent with Option “B” of the proposed Land Use Code regulations, notice is required
for any oil and gas operation to surface owners within two thousand six hundred forty (2,640) feet of the parcel and
to persons registered in writing with the Planning Director.
Closed Loop Pitless Systems – are required for the Containment and/or Recycling of Drilling and Completion Fluids.
Wells shall be drilled, completed and operated using closed loop, pitless systems for containment and/or recycling of
all drilling, completion, flowback and produced fluids.
Chemical disclosure and storage - the City will be provided, in table format, the name, Chemical Abstract Services
(CAS) number, volume, storage, containment and disposal method for all drilling and completion chemicals (solids,
fluids, and gases) used on the well pad. Fracture chemicals will be uploaded onto the Frac Focus website. The City
will also post such information on the City website. The Company will not permanently store hydraulic fracturing
chemicals, flowback from hydraulic fracturing, or produced water in the current City limits.
Electric equipment – Prospect Energy will be required to utilize electric-powered engines for motors,
compressors, and drilling equipment and for pumping systems when feasible in order to mitigate noise and reduce
emissions.
Emergency preparedness plan – Prospect Energy is required to develop an emergency preparedness plan for each
specific facility site, which shall be in compliance with the International Fire Code. Among other provisions, the plan
shall be filed with the Poudre Fire Authority and the City of Fort Collins Office of Emergency Management and updated
on an annual basis or as conditions change (responsible field personnel change, ownership changes, etc.). The plan
includes a provision establishing 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
Prospect Energy.
Air Quality – Prospect Energy must comply with emissions regulations as required by State and Federal laws. In
addition, there will be no uncontrolled venting of methane. All gas vapors will be captured to the extent practicable.
Vapor capture equipment will operate at 98% efficiency or better. There are no gas sales lines in the Fort Collins field
because the quantity and quality of gas is low and not marketable. If salable gas were to occur in the UDA, a sales
line would be constructed. The Operator will develop and maintain a leak detection and component repair (LDAR)
program according to EPA Method 21 for equipment used in permanent operations. LDAR will be performed on newly
installed equipment, and then on an annual basis. A forward-looking infrared (FLIR) camera will be used as the
preferred implementation method of EPA Method 21 as available from the state; if unavailable, other methods will be
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used in compliance with this method. Upon request from the City, Prospect Energy will implement EPA Method 21
should additional concerns arise. At least once per year, Prospect Energy will notify the City prior to FLIR camera use
in case the City wishes to observe the method.
Prospect Energy and the City will split the costs of baseline sampling and analytical work performed by a third party
consultant agreeable to both parties over a five (5) day sampling period. Prospect Energy will conduct air sampling
during well completion. Periodic air monitoring will be performed for hydrogen sulfide (H2S), a hazardous air pollutant
(HAP). Prospect Energy will perform field monitoring using the Jerome 631 XC or equivalent instrument annually, or
until such time that odors are not detected past the Fort Collins Tank Battery fence line in City Limits. The City may
require additional air monitoring as needed to respond to emergency events such as spill, process upsets, or
accidental releases or in response to odor complaints in City Limits.
During well completion, the capture and beneficial use of natural gas is preferred over flaring. However since the Fort
Collins field has so little natural gas it is not reasonable to capture the gas and as such minimal flaring will occur. What
flaring does occur will be monitored twenty-four (24) hours per day. During production the flare shall be fired with
natural gas and shall be operated with a ninety eight (98) percent or higher VOC destruction efficiency. An automatic
pilot system shall be used when feasible. Other ignition systems will include the installation and operation of a
telemetry alarm system or an on-site visible indicator showing proper function.
Water Quality Monitoring Plan – Prospect Energy shall comply with COGCC Rule 609. In summary, this requires
pre- and post-drilling testing. The rules require oil and gas operators to sample all “Available Water Sources” (owner
has given consent for sampling and testing and has consented to having the sample data obtained made available
to the public), with a cap of four (4) water sources, within one-half (1/2) mile radius of a proposed well, multi-well site,
or dedicated injection well. Water sources include registered water wells, permitted or adjudicated springs, and certain
monitoring wells. Prospect Energy agrees to the following requirements above and beyond the COGCC requirements:
analyzing for dissolved metals as indicated in the Land Use Code; sampling intervals to be baseline (before drilling),
post-drilling at one, three, and six years. Analytical results will be shared with the COGCC, the City, and the landowner.
All spills, for new and existing wells, shall be managed in accordance with COGCC regulations.
Soil Gas Monitoring – The City, at its discretion, may conduct soil gas monitoring to assess well casing integrity. This
would be typically completed within 90 days of new well completion. The City shall notify the Operator prior to entering
the site for soil gas monitoring.
Spills - The Company shall comply with COGCC Rule 609 “Spills and Releases”, and notify the City and whenever
there is notification to the COGCC. The Company shall also copy the City on any written correspondence to the
COGCC or other regulatory authority.
Transportation and circulation - Prospect Energy shall include in their applications detailed descriptions of all
proposed access routes for equipment, water, sand, waste fluids, waste solids, mixed waste, and all other material
to be hauled on the public streets and roads of the City. The submittal shall also include the estimated weights of
vehicles when loaded, a description of the vehicles, including the number of wheels and axles of such vehicles, trips
per day and any other information required by the Traffic Engineer. Preliminary information is required for this item
for the Conceptual Review meeting, in accordance with Exhibit A. The Company shall comply with all Transportation
and Circulation requirements as contained in the Land Use Code as may be reasonably required by the City’s Traffic
Engineer.
Wastewater and Waste Management - There will be minimal waste water in the Fort Collins Field, as there will be
no tank batteries (produced water and oil storage) in the City for the Fort Collins field. As described in “Closed Loop
System” and “Green Completions,” there is no discharge of fluids and fluids are contained. Storage, transportation,
and treatment of wastes during well drilling and completion are handled by third party contractors, under the direction
of the Operator. Waste is stored in tanks, transported by tanker truck, and disposed of at licensed disposal facilities.
In the UDA, new secondary containment shall be constructed of steel, with sufficient perimeter and height to hold one
and one-half (1.5) times the volume of the largest tank and sufficient freeboard to prevent overflow. No potential
ignition sources shall be installed inside the secondary containment area unless the containment enclosed a fired
vessel. The requirements for secondary containment will meet the Fort Collins Stormwater Criteria Manual. No land
treatment of oil impacted or contaminated drill cuttings are permitted. The use of a closed loop drilling system
precludes discharge of produced water or flowback to the ground or the use of pits. Produced water or flowback will
not be used for dust suppression. A copy of the field’s Spill Prevention, Control, and Countermeasure Plan (SPCC)
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will be given to the City, which describes spill prevention and mitigation practices. The Company will provide the City
documentation of waste disposal and its final disposition.
Water supply – Prospect Energy will identify in the site plan its source for water used in both the drilling and
production phases of operations. The sources and amount of water used in the City shall be documented and this
record shall be provided to the City annually or sooner, upon request of the City Manager. The disposal of water used
on site shall also be detailed including anticipated haul routes, approximate number of vehicles needed to supply and
dispose of water, and the final destination for water used in operation.
Comparison with LUC Option “B”
During Council deliberations, direction was given to staff to proceed with negotiations for an Agreement with Prospect
Energy that was consistent with the Land Use Code provisions reviewed by Council in Ordinance No. 144. While
Ordinance No. 144 was not adopted it contained regulation for oil and gas exploration and production. One of the
options was for a single-track development review process that generally contained more stringent regulations than
currently required by the COGCC and was described as Option “B”. Staff prepared a matrix illustrating how the
proposed agreement with Prospect Energy meets or exceeds requirements in Option B (Attachment 3).
Other Conditions of the Agreement
Through this Agreement, Prospect Energy will comply with all BMPs for New Wells as defined as a “Company-
operated well spudded during the term of this agreement, and located on either a currently existing well pad or a new
well pad that is located within the City limits.” In other words, BMPs will not apply to previously developed wells either
inside or outside the city limits owned by Prospect Energy. Approving this agreement requires Prospect Energy to
comply with the terms of the Agreement and removes any further development review permitting process. However,
the Agreement provides for public and staff notice, staff review and periodic inspections of any New Wells. Prospect
Energy will also be required to use the most stringent regulation in effect whether the regulation is a State, Federal
or required by this Agreement.
The term proposed in the Agreement is for five (5) years with successive five (5) year terms, until either Party wishes
to terminate the Agreement. The Agreement is binding to anyone who acquires either the Fort Collins Field or the
Undeveloped Acreage (UDA). There is also a non-performance clause in the Agreement which allows for mediation
and court remedies in the event the performance is not “cured.”
If Council approves this agreement, Prospect Energy has indicated they would continue operating the Fort Collins Field
and potentially increase the number of wells by six (6) to eight (8). As required by a SUA all new wells will be drilled
from existing well pads thus minimizing any future surface impact from the new drilling. It is likely that hydraulic
fracturing would be utilized in the operation of the field. This fracturing would not be in conjunction with horizontal
drilling and does not require intensive water usage seen in other natural gas developments. For example, the last six
(6) hydraulic fracturing processes in the Muddy J Formation - Fort Collins Field averaged 114,129 gallons of water
compared to 380,272 for a Wattenberg Vertical well or a Wattenberg Horizontal well requiring 2,992,374 gallons (data
provided by COGCC). In addition, it is likely that the Fort Collins Field will not produce any marketable gas due to the
extremely low quantity of gas contained in the field.
Prospect Energy also holds certain leasehold interests within the City described as the Undeveloped Area (UDA) as
depicted in (Attachment #2). If Council approves this agreement Prospect Energy intends to explore oil and gas
development in the UDA. It should be noted that Prospect Energy has Surface Use Agreements with the surface
owners for the Fort Collins Field (since 1988, amended 2001) and the UDA (2011). Those agreements govern any
potential well locations and associated facilities within the Subdivisions and other specified terms, including, but not
limited to, landscaping and fencing around wells and associated production equipment.
FINANCIAL / ECONOMIC IMPACTS
A true triple bottom line analysis includes an assessment of environmental, social, and economic impacts. Staff
analysis to date has focused on potential and possible environmental impacts if hydraulic fracturing is allowed. Staff
was unable to conclusively determine financial impacts of any health and safety hazard related to hydraulic fracturing
due to the significant number of variables that relate to the hydraulic fracturing process, transportation of material and
waste produced, and removal of waste materials. A social impact analysis has not yet been undertaken for this
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discussion. It is assumed that social impacts of hydraulic fracturing are discussed and addressed in terms of concerns
about health impacts, impacts to property and housing values, and quality of life.
Prospect Energy indicates that without this Agreement they would no longer be able to adequately operate the Fort
Collins Field or expand into other existing lease holdings currently within the city limits.
ENVIRONMENTAL IMPACTS
Documented in Agenda Item Summary (AIS) 26, prepared for Council Hearing February 19, 2013.
STAFF RECOMMENDATION
Staff recommends adoption of Resolution 2013-024. If adopted, staff recommends exempting Prospect Energy from
the moratorium enacted by Ordinance No. 145, 2013.
ATTACHMENTS
1. Vicinity Map
2. Fort Collins Field & UDA
3. Matrix Comparing Agreement & LUC Option B
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 1
Oil and Gas
Operator Agreement Comparison with Colorado Oil and Gas Conservation Commission Regulations
How this Matrix is Organized: This matrix compares the proposed Operator Agreeement with the regulations from the Colorado Oil and Gas Conservation
Commission (COGCC). The first column includes the Best Management Practices from Appendix A (or where noted, the body of the Operator Agreement) as
compared to the different standards from the COGCC.
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
1: General Application Procedure
Operator Agreement Body:
4. City Regulatory Approvals. The Company shall not be required to
obtain any project development plan or final plan approval from the City
to conduct its oil and gas operations within the City limits, as long as the
Company complies with the terms and conditions contained herein, and
this Agreement shall control all oil and gas operations conducted by the
Company within the City limits. Prior to the submission of a COGCC Form
2 and/or Form 2A to the COGCC, the Company shall meet with the City
to review the proposed oil and gas operation to ensure compliance with
this Agreement, all applicable state and federal regulations, and any site‐
specific concerns, which concerns may include overall project impacts and
economically and technically feasible mitigation measures or BMPs
related to field design and infrastructure construction to minimize
potential adverse impacts to public health, safety and welfare. At such
time, if at all, that the City and Larimer County, Colorado (the “County”)
enter into a written agreement that authorizes the City to regulate the oil
and gas operations of the Company within the Growth Management
Area, such operations shall thereafter be governed by the terms and
conditions of this Agreement and shall be subject to the City’s regulatory
authority as provided in this Agreement. “Growth Management Area”
shall be as described in that certain Intergovernmental Agreement
entered into by the City of Fort Collins and Larimer County on June
24,2008, nunc pro func [sic] October 17, 2006.
Appendix A
1. Regulations. The Company shall comply with all applicable state and
federal regulations in addition to the terms of this agreement and the
COGCC issues a Form 2 and Form 2A permit but allows local government permitting
and site review.
Form 2 is the Application for Permit to Drill (APD) and Form 2A is the Oil and Gas
Location Assessment which reviews each well/well pad’s suitability for permitting.
COGCC rules adopted January 9, 2013 (in effect August 1, 2013) provide for local
neighborhood and surface owner meetings as conditions for drilling within certain
distances of occupied buildings.
(New rules) 305. FORM 2 AND 2A APPLICATION PROCEDURES
a. Pre‐application notifications. For Oil and Gas Locations proposed within an Urban
Mitigation Area or within the Buffer Zone Setback, an Operator shall provide a
“Notice of Intent to Conduct Oil and Gas Operations” to the persons specified herein
not less than thirty (30) days prior to submitting a Form 2A Oil and Gas Location
Assessment to the Director.
(1) Urban Mitigation Area Notice to Local Government. For Oil and Gas Locations
within an Urban Mitigation Area, an Operator shall notify the local government in
writing that it intends to apply for an Oil and Gas Location Assessment. Such
notice shall be provided to the Local Governmental Designee in those jurisdictions
that have designated an LGD, and to the planning department in jurisdictions that
have no LGD. The notice shall include a general description of the proposed Oil
and Gas Facilities, the location of the proposed Oil and Gas Facilities, the
anticipated date operations (by calendar quarter and year) will commence, and
that an additional notice pursuant to Rule 305.c. will be sent by the Operator. This
notice shall serve as an invitation to the local government to engage in discussions
with the Operator regarding proposed operations and timing, local government
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 2
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
Best Management Practices included below. Whichever regulation is
most stringent shall apply.
3. Conceptual Review. No less than thirty (30) days prior to the
submission of an Application for a Permit to Drill, the Company agrees to
schedule a meeting with the City to review the proposed new well or
drilling activity. The goal of this meeting shall be for staff and the
applicant to review the proposed oil and gas operation in a manner that
ensures compliance with the operator agreement and applicable state
and federal regulations. This pre‐submittal meeting shall also allow the
applicant and staff to explore site‐specific concerns, to discuss project
impacts and potential mitigation methods including field design and
infrastructure construction to minimize impacts, to discuss coordination
of field design with other existing or potential development and
operators, to identify sampling and monitoring plans for air and water
quality, and other elements of the operator agreement as contained in
Appendices A and B. Based upon the foregoing, applicants are
encouraged to conduct the pre‐submittal meeting with the City prior to
completing well siting decisions, to the extent reasonably feasible.
jurisdictional requirements, and opportunities to collaborate regarding site
development. A local government may waive its right to notice under this
provision at any time by providing written notice to an Operator and the Director.
(2) Exception Zone and Buffer Zone Setback Notice to the Surface Owner and
Building Unit Owners. For Oil and Gas Locations proposed within the Exception
Zone or Buffer Zone Setback, Operators shall notify the Surface Owner and the
owners of all Building Units that a permit to conduct Oil and Gas Operations is
being sought. The Operator may rely on the county assessor tax records to
identify the persons entitled to receive the Notice.
Notice shall include the following:
A. The Operator’s contact information;
B. The location and a general description of the proposed Well or Oil and Gas
Facilities;
C. The anticipated date operations will commence (by calendar quarter and
year);
D. The Local Governmental Designee’s (LGD) contact information;
E. Notice that the Building Unit owner may request a meeting to discuss the
proposed operations by contacting the LGD or the Operator; and
F. A “Notice of Comment Period” will be sent pursuant to Rule 305.c. when the
public comment period commences.
2: Setbacks
2. Setbacks for New Wells. It is the intent of the Company to maximize
equipment and wellhead setbacks from occupied buildings and
residences beyond the setbacks required by the COGCC to the extent
feasible and practicable.
The Parties recognize that a portion of the Field is within the Fort Collins
City Limits and as such, development has occurred within the already
established Field. The surface owner has obtained permitted plats for
residential areas in the vicinity of existing oil and gas activities, including a
constructed city park and contemplated building units and public roads
within three hundred fifty (350) feet of an existing well. Further, the
Parties acknowledge that the Commission rules require a minimum of five
hundred (500) feet safety setback for New Well construction from a
building unit and one thousand feet (1,000) from a high occupancy
COGCC modified setback rules on January 9, 2013 and they go into effect August 1,
2013.
604. SETBACK AND MITIGATION MEASURES FOR OIL AND GAS FACILITIES,
DRILLING, AND WELL SERVICING OPERATIONS
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 3
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
building.
Any New Wells drilled in the UDA shall conform to the Commission
setback rules then in effect, except for any New Well in the UDA drilled
before August 1, 2013, shall be subject to the Commission setback rules
to take effect on August 1, 2013. In the Fort Collins Field, New Wells shall
be constructed on existing Well Pads, which due to previous setback
requirements, and City approval of residential development, do not
conform to five hundred (500) feet setbacks, and are given an exemption
from the Commission in the Rules now in effect.
The Parties recognize the existence of a Surface Use Agreement (the
“SUA”) between the Company and the surface owner which expressly
governs the locations of wells and associated facilities within the Water’s
Edge, Richard’s Lake and Hearthfire subdivisions (the “Subdivisions”), and
that certain terms found in the SUA may affect Commission setbacks and
other Commission rules.
2A or associated Form 2, or obtains a variance pursuant to Rule 502;
and
ii. the Operator certifies it has complied with Rules 305.a, 305.c., and 306.e.;
and
iii. the Form 2A or Form 2 contains conditions of approval related to site
specific mitigation measures sufficient to eliminate, minimize or mitigate
potential
adverse impacts to public health, safety, welfare, the environment, and
wildlife to the maximum extent technically feasible and economically
practicable; or
iv. the Oil and Gas Location is approved as part of a Comprehensive Drilling
Plan pursuant to Rule 216.
B. Non‐Urban Mitigation Area Locations. Except as provided in subsection
604.b., below, the Director shall not approve a Form 2 or Form 2A proposing to
locate a Well or a Production Facility within an Exception Zone Setback not in
an Urban
Mitigation Area unless the Operator certifies it has complied with Rules 305.a.,
305.c., and 306.e., and the Form 2A or Form 2 contains conditions of approval
related to site specific mitigation measures sufficient to eliminate, minimize or
mitigate potential adverse impacts to public health, safety, welfare, the
environment, and wildlife to the maximum extent technically feasible and
economically practicable.
(2) Buffer Zone Setback. No Well or Production Facility shall be located one
thousand (1,000) feet or less from a Building Unit until the Operator certifies it
has complied with Rule 306.e. and the Form 2A or Form 2 contains conditions of
approval related to site specific mitigation measures as necessary to eliminate,
minimize or mitigate potential adverse impacts to public health, safety, welfare,
the environment, and wildlife.
(3) High Occupancy Buildings. No Well or Production Facility shall be located one
thousand (1,000) feet or less from a High Occupancy Building Unit without
Commission approval following Application and Hearing. Exception Zone Setback
mitigation measures pursuant to Rule 604.c. shall be required for Oil and Gas
Locations within one thousand (1,000) feet of a High Occupancy Building, unless
the Commission determines otherwise.
(4) Designated Outside Activity Areas. No Well or Production Facility shall be
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 4
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
located three hundred fifty (350) feet or less from the boundary of a Designated
Outside Activity. The Commission, in its discretion, may establish a setback of
greater than three hundred fifty (350) feet based on the totality of circumstances.
Buffer Zone Setback mitigation measures pursuant to Rule 604.c. shall be
required for Oil and Gas Locations within one thousand (1,000) feet of a
Designated Outside Activity Area, unless the Commission determines otherwise.
(5) Maximum Achievable Setback. If the applicable setback would extend beyond
the area on which the Operator has a legal right to locate the Well or Production
Facilities, the Operator may seek a variance under Rule 502.b. to reduce the
setback to the maximum achievable distance.
3: Notice
4. Mailed Notice. The City shall mail notice of the pending Application for
a Permit to Drill no more than ten (10) days after the conceptual review
meeting has taken place. The Company shall reimburse the City for the
costs of the mailing. Owners of record shall be ascertained according to
the records of the Larimer County Assessor’s Office, unless more current
information is made available in writing to the City prior to the mailing of
the notices. Notice of the pending application shall include reference to
the neighborhood meeting, if applicable, and be made as follows:
⼀ To the surface owners of the parcels of land on which the oil and
gas operation is proposed to be located;
⼀ To the surface owners of the parcels of land within five hundred
(500) feet of a proposed gathering line;
⼀ To the surface owners of the parcels of land within two thousand
six hundred forty (2,640) feet of the parcel on which the oil and gas
operation is proposed to be located; and
⼀ To persons registered in writing with the City as representing
bona fide neighborhood groups and organizations and homeowners'
associations within the area of notification.
(5) Application Notice to Surface Owners and Surrounding Landowners. This
subsection shall apply to oil and gas operations instead of the notice provisions
contained in Section 2.2.6 of this Land Use Code.
(a) The Director shall mail notice no less than five (5) days after the
application has been deemed complete by the Director. Notice of the
application shall be made as follows:
1. To the surface owners of the parcels of land on which the oil and gas
operation is proposed to be located;
2. To the surface owners of the parcels of land within five hundred
(500) feet of a proposed gathering line;
3. To the surface owners of the parcels of land within two thousand
six hundred forty (2,640) feet of the parcel on which the oil and gas
operation is proposed to be located; and
4. To persons registered in writing with the Director as representing bona
fide neighborhood groups and organizations and homeowners' associations
within the area of notification.
(b) The Director shall also provide public notice of the application received
by posting the application on the City’s website for public review, but excluding
any information required by the Commission to be kept confidential.
(c) Notice shall also be provided by the Director of the neighborhood meeting
and public hearing in accordance with Section 2.2.6 of this Land Use Code.
(6) Posting Site. The Applicant shall post a sign on the site in a location
visible to the public (i.e., visible from a public road) stating that a development plan
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 5
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
5. Posted Notice. The real property proposed to be developed shall also
be posted with a sign, giving notice to the general public of the proposed
development. For parcels of land exceeding ten (10) acres in size, two (2)
signs shall be posted. The size of the sign(s) required to be posted shall
be as established in the Supplemental Notice Requirements of Section
2.2.6(D) of the City’s Land Use Code. Such signs shall be provided by the
City and shall be posted on the subject property in a manner and at a
location or locations reasonably calculated by the City to afford the best
notice to the public, which posting shall occur within ten (10) days
following the Conceptual Review meeting.
6. Neighborhood Meetings. A neighborhood meeting shall be required
on any New Well, even on existing Well Pads, that requires an
Application for a Permit to Drill. Notice of the neighborhood meeting
shall be provided in accordance with Sections 4 and 5 above. The
Company shall attend the neighborhood meeting. The City shall be
responsible for scheduling and coordinating the neighborhood meeting
and shall hold the meeting in the vicinity of the proposed development. A
written summary of the neighborhood meeting shall be prepared by the
City. The written summary shall be included in the Local Government
Designee (LGD) comments provided to the COGCC at the time of the
public hearing or permit review to consider the Application for a Permit
to Drill.
7. Notification to the City and the public regarding commencement of
operations. Prior to the commencement of any new drilling operations,
the Company shall provide to the City Manager for posting on the
website the information outlined in Appendix B regarding
commencement of operations, which the Company may revise from
time‐to‐time during operations, with prior approval from the City.
review application has been applied for and providing the phone number of the
Planning Department where information regarding the application may be
obtained. All signs for oil and gas operations shall be twelve (12) square feet in size.
For parcels of land exceeding ten (10) acres in size, two (2) signs shall be posted.
Such signs shall be provided by the Director and shall be posted on the subject
property in a manner and at a location or locations reasonably calculated by the
Director to afford the best notice to the public, which posting shall occur within
fourteen (14) days following submittal of a development application to the Director.
4: General Requirements
8. Inspections. The City shall have the right to inspect the Company’s
operations and its sites during business hours, upon the giving of twenty‐
four (24) hour advance written notice to the Company.
COGCC maintains an inspection protocol and scheduling based upon several factors.
This inspection protocol is not codified in a rule. Each area has a lead field inspector
whose job is to inspect a site at least once during well completion, based upon
complaints or in a rotation. This inspector may cite an operator for violations of
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 6
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
COGCC rules and has access to the well site for such inspections without prior
notice.
9. Containment berms. The Company shall utilize steel‐rim berms around
tanks and separators at new Well Pads. All berms and containment
devices shall be inspected at regular intervals and maintained in good
condition. No potential ignition sources shall be installed inside the
secondary containment area unless the containment area encloses a fired
vessel. Refer to American Petroleum Institute Recommended Practices,
API RP ‐ D16.
a) Containment berms shall be constructed of steel rings, designed
and installed to prevent leakage and resist degradation from erosion
or routine operation.
b) Secondary containment for tanks shall be constructed with a
synthetic or engineered liner that contains all primary containment
vessels and flowlines and is mechanically connected to the steel ring
to prevent leakage.
c) For locations within five hundred (500) feet and upgradient of a
surface water body, tertiary containment, such as an earthen berm, is
required around production facilities.
Rule 604.a.4
Berms or other secondary containment devices shall be constructed around crude
oil, condensate, and produced water tanks to provide secondary containment for
the largest single tank and sufficient freeboard to contain precipitation. Berms and
secondary containment devices and all containment areas shall be sufficiently
impervious to contain any spilled or released material. Berms and secondary
containment devices shall be inspected at regular intervals and maintained in good
condition. No potential ignition sources shall be installed inside the secondary
containment area unless the containment area encloses a fired vessel.
Rule 603.e.12 DRILLING AND WELL SERVICING OPERATIONS AND HIGH DENSITY
AREA RULES
Berm construction. Berms or other secondary containment devices in high density
areas shall be constructed around crude oil, condensate, and produced water
storage tanks and shall enclose an area sufficient to contain and provide secondary
containment for one‐hundred fifty percent (150%) of the largest single tank. Berms
or other secondary containment devices shall be sufficiently impervious to contain
any spilled or released material. No more than two (2) crude oil or condensate
storage tanks shall be located within a single berm. All berms and containment
devices shall be inspected at regular intervals and maintained in good condition. No
potential ignition sources shall be installed inside the secondary containment area
unless the containment area encloses a fired vessel. Refer to American Petroleum
Institute Recommended Practices, API RP ‐ D16.
10. Closed Loop Pitless Systems for the Containment and/or Recycling of
Drilling and Completion Fluids. Wells shall be drilled, completed and
operated using closed loop pitless systems for containment and/or
recycling of all drilling, completion, flowback and produced fluids.
(New Rules)
604.c. Mitigation Measures.
The following requirements apply to an Oil and Gas Location within a Designated
Setback Location and such requirements shall be incorporated into the Form 2A or
associated Form 2 as Conditions of Approval.
B. Closed Loop Drilling Systems – Pit Restrictions.
i. Closed loop drilling systems are required within the Buffer Zone Setback.
ii. Pits are not allowed on Oil and Gas Locations within the Buffer Zone Setback,
except fresh water storage pits, reserve pits to drill surface casing, and emergency
pits as defined in the 100‐Series Rules.
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 7
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
iii. Fresh water pits within the Exception Zone shall require prior approval of a Form
15 pit permit. In the Buffer Zone, fresh water pits shall be reported within 30‐days of
pit construction.
iv. Fresh water storage pits within the Buffer Zone Setback shall be conspicuously
posted with signage identifying the pit name, the operator’s name and contact
information, and stating that no fluids other than fresh water are permitted in the
pit. Produced water, recycled E&P waste, or flowback fluids are not allowed in fresh
water storage pits.
v. Fresh water storage pits within the Buffer Zone Setback shall include emergency
escape provisions for inadvertent human access.
11. Anchoring. All equipment at drilling and production sites shall be
anchored to the extent necessary to resist flotation, collapse, lateral
movement, or subsidence. All guy line anchors left buried for future use
shall be identified by a marker of bright color not less than four (4) feet in
height and not greater than one (1) foot east of the guy line anchor.
Rule 603.k. Statewide equipment anchoring requirements.
All equipment at drilling and production sites in geological hazard and floodplain
areas shall be anchored to the extent necessary to resist flotation, collapse, lateral
movement, or subsidence.
603.e.(11) (In high density areas) Guy line anchors. All guy line anchors left buried
for future use shall be identified by a marker of bright color not less than four (4)
feet in height and not greater than one (1) foot east of the guy line anchor.
12. Burning. No open burning shall occur on the site of any oil and gas
operation.
Rule 603.j. Statewide equipment, weeds, waste, and trash requirements.
All locations, including wells and surface production facilities, shall be kept free of
the following: equipment, vehicles, and supplies not necessary for use on that lease;
weeds; rubbish, and other waste material. The burning or burial of such material on
the premises shall be performed in accordance with applicable local, state, or
federal solid waste disposal regulations and in accordance with the 900‐Series Rules.
In addition, material may be burned or buried on the premises only with the prior
written consent of the surface owner.
13. Chains. Traction chains from heavy equipment shall be removed
before entering a City street.
Staff did not find COGCC regulations addressing chains.
14. Chemical disclosure and storage. The City shall be provided, in table
format, the name, Chemical Abstracts Service (CAS) number, volume,
storage, containment and disposal method for all drilling and completion
chemicals (solids, fluids, and gases) used on the Well Pad. Fracture
chemicals shall be uploaded onto the Frac Focus website. The Company
shall not permanently store hydraulic fracturing chemicals, flowback from
205A. HYDRAULIC FRACTURING CHEMICAL DISCLOSURE.
a. Applicability. This Commission Rule 205a applies to hydraulic fracturing
treatments performed on or after April 1, 2012.
b. Required disclosures.
(1) Vendor and service provider disclosures. A service provider who performs
any part of a hydraulic fracturing treatment and a vendor who provides
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hydraulic fracturing, or produced water in the City limits. hydraulic fracturing additives directly to the operator for a hydraulic fracturing
treatment shall, with the exception of information claimed to be a trade secret,
furnish the operator with the information required by subsection
205A.b.(2)(A)(viii) – (xii) and subsection 205A.b.(2)(B), as applicable, and with
any other information needed for the operator to comply with subsection
205A.b.(2). Such information shall be provided as soon as possible within 30
days following the conclusion of the hydraulic fracturing treatment and in no
case later than 90 days after the commencement of such hydraulic fracturing
treatment.
(2) Operator disclosures.
A. Within 60 days following the conclusion of a hydraulic fracturing treatment,
and in no case later than 120 days after the commencement of such hydraulic
fracturing treatment, the operator of the well must complete the chemical
disclosure registry form and post the form on the chemical disclosure registry,
including:
i. the operator name;
ii. the date of the hydraulic fracturing treatment;
iii. the county in which the well is located;
iv. the API number for the well;
v. the well name and number;
vi. the longitude and latitude of the wellhead;
vii. the true vertical depth of the well;
viii. the total volume of water used in the hydraulic fracturing treatment of
the well or the type and total volume of the base fluid used in the hydraulic
fracturing treatment, if something other than water;
ix. each hydraulic fracturing additive used in the hydraulic fracturing fluid
and the trade name, vendor, and a brief descriptor of the intended use or
function of each hydraulic fracturing additive in the hydraulic fracturing
fluid;
x. each chemical intentionally added to the base fluid;
xi. the maximum concentration, in percent by mass, of each chemical
intentionally added to the base fluid; and
xii. the chemical abstract service number for each chemical intentionally
added to the base fluid, if applicable.
B. If the vendor, service provider, or operator claim that the specific identity
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of a chemical, the concentration of a chemical, or both the specific identity
and concentration of a chemical is/are claimed to be a trade secret, the
operator of the well must so indicate on the chemical disclosure registry form
and, as applicable, the vendor, service provider, or operator shall submit to
the Director a Form 41 claim of entitlement to have the specific identity of a
chemical, the concentration of a chemical, or both withheld as a trade secret.
The operator must nonetheless disclose all information required under
subsection 205A.b.(2)(A) that is not claimed to be a trade secret. If a chemical
is claimed to be a trade secret, the operator must also include in the chemical
registry form the chemical family or other similar descriptor associated with
such chemical.
C. At the time of claiming that a hydraulic fracturing chemical, concentration,
or both is entitled to trade secret protection, a vendor, service provider or
operator shall file with the commission claim of entitlement, Form 41,
containing contact information. Such contact information shall include the
claimant’s name, authorized representative, mailing address, and phone
number with respect to trade secret claims. If such contact information
changes, the claimant shall immediately submit a new Form 41 to the
Commission with updated information.
D. Unless the information is entitled to protection as a trade secret,
information submitted to the Commission or posted to the chemical
disclosure registry is public information.
(3) Ability to search for information.
A. If the Commission determines, as of January 1, 2013, that:
i. The chemical disclosure registry does not allow the Commission staff and
the public to search and sort the registry for Colorado information by
geographic area, ingredient, chemical abstract service number, time period,
and operator; and
ii. There is no reasonable assurance that the registry will allow for such
searches by a date certain acceptable to the Commission,
Then the provisions of subsection 205A.b.(3)(B) below shall apply.
B. Beginning February 1, 2013, any operator who posts a chemical disclosure
form on the chemical disclosure registry shall also submit the form to the
Commission in an electronic format acceptable to the Commission. As soon
thereafter as practicable, the Commission shall make such forms available on
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the Commission’s website in a manner that allows the public to search the
information and sort the forms by geographic area, ingredient, chemical
abstract service number, time period and operator, as practicable.
(4) Inaccuracies in information. A vendor is not responsible for any inaccuracy in
information that is provided to the vendor by a third party manufacturer of the
hydraulic fracturing additives. A service provider is not responsible for any
inaccuracy in information that is provided to the service provider by the vendor.
An operator is not responsible for any inaccuracy in information provided to the
operator by the vendor or service provider.
(5) Disclosure to health professionals. Vendors, service companies, and
operators shall identify the specific identity and amount of any chemicals
claimed to be a trade secret to any health professional who requests such
information in writing if the health professional provides a written statement of
need for the information and executes a confidentiality agreement, Form 35.
The written statement of need shall be a statement that the health professional
has a reasonable basis to believe that (1) the information is needed for purposes
of diagnosis or treatment of an individual, (2) the individual being diagnosed or
treated may have been exposed to the chemical concerned, and (3) knowledge
of the information will assist in such diagnosis or treatment. The confidentiality
agreement, Form 35, shall state that the health professional shall not use the
information for purposes other than the health needs asserted in the statement
of need, and that the health professional shall otherwise maintain the
information as confidential. Where a health professional determines that a
medical emergency exists and the specific identity and amount of any chemicals
claimed to be a trade secret are necessary for emergency treatment, the
vendor, service provider, or operator, as applicable, shall immediately disclose
the information to that health professional upon a verbal acknowledgement by
the health professional that such information shall not be used for purposes
other than the health needs asserted and that the health professional shall
otherwise maintain the information as confidential. The vendor, service
provider, or operator, as applicable, may request a written statement of need,
and a confidentiality agreement, Form 35, from all health professionals to
whom information regarding the specific identity and amount of any chemicals
claimed to be a trade secret was disclosed, as soon as circumstances permit.
Information so disclosed to a health professional shall in no way be construed as
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publicly available.
c. Disclosures not required. A vendor, service provider, or operator is not required
to:
(1) disclose chemicals that are not disclosed to it by the manufacturer, vendor,
or service provider;
(2) disclose chemicals that were not intentionally added to the hydraulic
fracturing fluid; or
(3) disclose chemicals that occur incidentally or are otherwise unintentionally
present in trace amounts, may be the incidental result of a chemical reaction or
chemical process, or may be constituents of naturally occurring materials that
become part of a hydraulic fracturing fluid.
d. Trade secret protection.
(1) Vendors, service companies, and operators are not required to disclose trade
secrets to the chemical disclosure registry. (2) If the specific identity of a
chemical, the concentration of a chemical, or both the specific identity and
concentration of a chemical are claimed to be entitled to protection as a trade
secret, the vendor, service provider or operator may withhold the specific
identity, the concentration, or both the specific identity and concentration, of
the chemical, as the case may be, from the information provided to the
chemical disclosure registry. Provided, however, operators must provide the
information required by Rule 205A.b.(2)(B) & (C). The vendor, service provider,
or operator, as applicable, shall provide the specific identity of a chemical, the
concentration of a chemical, or both the specific identity and concentration of a
chemical claimed to be a trade secret to the Commission upon receipt of a letter
from the Director stating that such information is necessary to respond to a spill
or release or a complaint from a person who may have been directly and
adversely affected or aggrieved by such spill or release. Upon receipt of a
written statement of necessity, such information shall be disclosed by the
vendor, service provider, or operator, as applicable, directly to the Director or
his or her designee and shall in no way be construed as publicly available.
The Director or designee may disclose information regarding the specific
identity of a chemical, the concentration of a chemical, or both the specific
identity and concentration of a chemical claimed to be a trade secret to
additional Commission staff members to the extent that such disclosure is
necessary to allow the Commission staff member receiving the information to
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assist in responding to the spill, release, or complaint, provided that such
individuals shall not disseminate the information further. In addition, the
Director may disclose such information to any Commissioner, the relevant
county public health director or emergency manager, or to the Colorado
Department of Public Health and Environment’s director of environmental
programs upon request by that individual. Any information so disclosed to the
Director, a Commission staff member, a Commissioner, a county public health
director or emergency manager, or to the Colorado Department of Public Health
and Environment’s director of environmental programs shall at all times be
considered confidential and shall not be construed as publicly available. The
Colorado Department of Public Health and Environment’s director of
environmental programs, or his or her designee, may disclose such information
to Colorado Department of Public Health and Environment staff members under
the same terms and conditions as apply to the director.
e. Incorporated materials. Where referenced herein, these regulations incorporate
by reference material originally published elsewhere. Such incorporation does not
include later amendments to or editions of the referenced material. Pursuant to
section 24‐4‐103 (12.5) C.R.S., the Commission maintains copies of the complete
text of the incorporated materials for public inspection during regular business
hours. Information regarding how the incorporated material may be obtained or
examined is available at the Commission’s office located at 1120 Lincoln Street,
Suite 801, Denver, Colorado 80203.
15. Color. Facilities shall be painted in a uniform, non‐contrasting, non‐
reflective color, to blend with the surrounding landscape and, with colors
that match the land rather than the sky. The color should be slightly
darker than the surrounding landscape.
804. VISUAL IMPACT MITIGATION
Production facilities, regardless of construction date, which are observable from any
public highway shall be painted with uniform, non‐contrasting, non‐reflective color
tones (similar to the Munsell Soil Color Coding System), and with colors matched to
but slightly darker than the surrounding landscape by September 1, 2010.
16. Cultural and Historical Resource Protection. If a significant surface or
sub‐surface archaeological site is discovered during construction, the
Company shall be responsible for immediately contacting the City to
report the discovery. If any disturbance of the resource occurs, the
Company shall be responsible for mitigating the disturbance to the
cultural or historical property through a data recovery plan approved by
the City.
Staff did not find COGCC regulations addressing Cultural and Historical Resources
Protection.
17. Discharge valves. Open‐ended discharge valves on all storage tanks, Staff did not find COGCC regulations addressing discharge valves.
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pipelines and other containers shall be secured where the operation site
is unattended or is accessible to the general public. Open‐ended
discharge valves shall be placed within the interior of the tank secondary
containment.
18. Dust suppression. Dust associated with on‐site activities and traffic
on access roads shall be minimized throughout construction, drilling
and operational activities such that there are no visible dust emissions
from access roads or the site to the extent practical given wind
conditions. No produced water or other process fluids shall be used for
dust suppression. The Company will avoid dust suppression activities
within three hundred (300) feet of the ordinary high water mark of any
waterbody, unless the dust suppressant is water. Material Safety Data
Sheets (MSDS) for any chemical based dust suppressant shall be
submitted to the City for approval prior to use.
(New Rules)
805.c. Fugitive dust.
Operators shall employ practices for control of fugitive dust caused by their
operations. Such practices shall include but are not limited to the use of speed
restrictions, regular road maintenance, restriction of construction activity during
high‐wind days, and silica dust controls when handling sand used in hydraulic
fracturing operations. Additional management practices such as road surfacing,
wind breaks and barriers, or automation of wells to reduce truck traffic may also be
required if technologically feasible and economically reasonable to minimize fugitive
dust emissions.
19. Electric equipment. Electric‐powered engines for motors,
compressors, and drilling equipment and for pumping systems shall be
used in order to mitigate noise and to reduce emissions when feasible.
(New Rules)
802.f. All Oil and Gas Facilities with engines or motors which are not electrically
operated that are within four hundred (400) feet of Building Units shall be equipped
with quiet design mufflers or equivalent. All mufflers shall be properly installed and
maintained in proper working order.
20. Emergency preparedness plan. The Company is required to develop
an emergency preparedness plan for each specific facility site, which shall
be in compliance with the International Fire Code. The plan shall be filed
with the Poudre Fire Authority and the City of Fort Collins Office of
Emergency Management and updated on an annual basis or as conditions
change (responsible field personnel change, ownership changes, etc.).
The emergency preparedness plan shall consist of at least the following
information:
a) Name, address and phone number, including twenty‐four (24)
hour emergency numbers for at least two persons responsible for
emergency field operations.
b) An as‐built facilities map in a format suitable for input into the
City’s GIS system depicting the 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
Portions of emergency planning, spill response, and emergency operation
procedures exist throughout the COGCC rules but there is not a requirement for an
emergency preparedness plan.
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transportation routes to and from exploration and development sites,
for emergency response and management purposes. The
information concerning pipelines and isolation valves shall be held
confidentially by the City's Office of Emergency Management and the
Battalion Chief, and shall only be disclosed in the event of an
emergency or to emergency responders. The City shall deny the right
of inspection of the as‐built facilities maps to the public pursuant to
C.R.S. § 24‐72‐204.
c) 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. 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 City‐approved Emergency Preparedness Plan shall be
reported to the local emergency dispatch and the COGCC Director in
accordance with COGCC regulations.
d) Detailed information identifying access or evacuation routes, and
health care facilities anticipated to be used.
e) A project specific emergency preparedness plan for any project
that involves drilling or penetrating through known zones of
hydrogen sulfide gas.
f) Detailed information showing that the Company has adequate
personnel, supplies, and training to implement the emergency
response plan immediately at all times during construction and
operations.
g) The Company shall have current Material Safety Data Sheets
(MSDS) for all chemicals used or stored on a site. The MSDS sheets
shall be provided immediately upon request to City officials, a public
safety officer, or a health professional.
h) The plan shall include a provision establishing a process by which
the Company 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 Company.
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i) All training associated with the Emergency Preparedness plan
shall be coordinated with the City’s Office of Emergency
Management and Poudre Fire Authority.
j) A provision obligating the Company to reimburse the appropriate
emergency response service providers for costs incurred in
connection with any emergency in accordance with Colorado State
Statutes.
21. Air quality. The Company must comply with emissions regulations
governed by the Colorado Department of Public Health and Environment
(CDPHE), Air Pollution Control Division (APCD). Air emissions from wells
shall be in compliance with the permit and control provisions of the
Colorado Air Quality Control Program, Title 25, Section 7, C.R.S., COGCC
Rule 805, and all state and federal regulations for the control of fugitive
dust, and control of ozone, ozone precursors, methane, and hazardous air
pollutants by the Larimer County Public Health Department, and the
CDPHE‐APCD. The Company must comply with 40 CFR Subpart OOOO as
published on August 16, 2012 (Quad O).
a) General Duty to Minimize Emissions. The Company shall
incorporate in the development plan; operations, procedures, and
field design features to the maximum extent feasible that minimize
air pollutant emissions including but not limited to:
1) Consolidation of product treatment and storage facilities
2) Centralization of compression facilities
3) Liquids gathering and water delivery systems
4) Telemetric control and monitoring systems
5) Pipeline infrastructure prior to well completion.
b) In the UDA, the Company will utilize a high‐low pressure vessel
(HLP) and vapor recovery unit (VRU) for New Wells that are placed on
production. The Company may remove the VRU at such time it
determines that the VRU system is no longer necessary due to
reduced emission recoveries and/or efficiencies, but no earlier than
one (1) year after the new well is placed on production. The
Company may opt to capture gas and send through a thermal oxidizer
324A. POLLUTION
a. The operator shall take precautions to prevent significant adverse environmental
impacts to air, water, soil, or biological resources to the extent necessary to protect
public health, safety and welfare, including the environment and wildlife resources,
taking into consideration cost‐effectiveness and technical feasibility to prevent the
unauthorized discharge or disposal of oil, gas, E&P waste, chemical substances,
trash, discarded equipment or other oil field waste.
b. No operator, in the conduct of any oil or gas operation shall perform any act or
practice which shall constitute a violation of water quality standards or
classifications established by the Water Quality Control Commission for waters of
the state, or any point of compliance established by the Director pursuant to Rule
324D. The Director may establish one or more points of compliance for any event of
pollution, which shall be complied with by all parties determined to be a responsible
party for such pollution.
c. No owner, in the conduct of any oil or gas operation, shall perform any act or
practice which shall constitute a violation of any applicable air quality laws,
regulations, and permits as administered 300‐41 by the Air Quality Control
Commission or any other local or federal agency with authority for regulating air
quality associated with such activities.
805. ODORS AND DUST
a. General. Oil and gas facilities and equipment shall be operated in such a manner
that odors and dust do not constitute a nuisance or hazard to public welfare.
b. Odors.
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in lieu of a HLP and VRU.
c) Plunger lifts are not typically used in the Fort Collins Field due to
insufficient gas. However if there is future use of plunger lifts,
emissions shall be controlled from the motor control valve using low
bleed pneumatic controllers.
d) There shall be no uncontrolled venting of methane. All gas vapors
shall be captured to the extent practicable. Vapor capture
equipment shall operate at ninety‐eight percent (98) percent
efficiency or better. There are no gas sales lines in the Fort Collins
field because the quantity and quality of gas is low and not
marketable. If salable gas were to occur in the UDA, a sales line shall
be constructed.
e) Flaring during drilling and completions:
During well completion, the capture and beneficial use of natural gas
is preferred over flaring. Minimal flaring may occur in the Fort Collins
field, because there is minimal gas in the field. Flaring shall be
continuously monitored on‐site by the Company, under twenty‐four
(24) hour watch and is regulated by COGCC Rules 317, 805B(3)B, and
912. No venting of gas may occur, except under COGCC Green
Completion Practices (Rule 805 B(3)B), or in very limited cases under
Rule 912 with the COGCC Director approval.
f) Flaring during production operations:
1) The flare shall be fired with natural gas and shall be operated
with a ninety eight (98) percent or higher VOC destruction
efficiency.
2) The flare shall be designed and operated in a manner that
shall ensure no visible emissions, pursuant to the provisions of 40
CFR 60.18(f), except for periods not to exceed a total of five (5)
minutes during any two (2) consecutive hours. Where applicable,
B. No violation of Rule 805.b.(1) shall be cited by the Commission, provided that
the practices identified in Rule 805.b.(2) are used.
(2) Production Equipment and Operations.
A. Condensate Tanks. All condensate tanks with a potential to emit volatile
organic compounds (VOC) of five (5) tons per year (tpy) or greater, located in
Garfield, Mesa, or Rio Blanco County and within 1/4 mile of a building unit,
educational facility, assembly building, hospital, nursing home, board and care
facility, jail, or designated outside activity area shall utilize a control device
capable of achieving 95% control efficiency of VOC and shall hold a valid permit
from the Colorado Department of Public Health and Environment, Air Pollution
Control Division, for the tank and control device. Condensate tanks meeting the
above criteria and existing on May 1, 2009 on federal lands and on April 1, 2009
on all other lands shall be in compliance with this subsection by October 1,
2009.
B. Crude Oil and Produced Water Tanks. All crude oil and produced water tanks
with a potential to emit VOC of five (5) tpy or greater, located in Garfield, Mesa,
or Rio Blanco County and within 1/4 mile of a building unit, educational facility,
assembly building, hospital, nursing home, board and care facility, jail, or
designated outside activity area shall utilize a control device capable of
achieving 95% control efficiency of VOC and shall hold a valid permit from the
Colorado Department of Public Health and Environment, Air Pollution Control
Division, for the tank and control device. Crude oil and produced water tanks
meeting the above criteria and existing on May 1, 2009 on federal lands and on
April 1, 2009 on all other lands shall be in compliance with this subsection by
October 1, 2009.
C. Glycol Dehydrators. All glycol dehydrators with a potential to emit VOC of
five (5) tpy or greater, located in Garfield, Mesa, or Rio Blanco County and
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flares shall also be in compliance with 5 CCR 1001‐9 Regulation 7
Section XVIIB for non‐condensate oil.
3) The flare shall be operated with a flame present at all times
when emissions may be vented to it, pursuant to the methods
specified in 40 CFR 60.18(f).
4) An automatic pilot system shall be used when feasible. Other
ignition systems may include the installation and operation of a
telemetry alarm system or an on‐site visible indicator showing
proper function.
g) Leak Detection and Repair (LDAR) – The Company shall develop
and maintain a leak detection and component repair program
according to EPA Method 21 for equipment used in permanent
operations. LDAR shall be performed on newly installed equipment,
and then on an annual basis. A Forward‐Looking Infrared (FLIR)
camera shall be used as the preferred implementation method of EPA
Method 21 as available from the state; if unavailable, other methods
shall be used in compliance with this method. Upon request from the
City, the Company shall implement EPA Method 21 upon additional
concerns. At least once per year, the Company shall notify the City
prior to FLIR camera use in case the City wishes to observe the
method.
h) One Time Baseline Air Quality Monitoring ‐ the Company and the
City shall split the cost for a one time Baseline Sampling and
Analytical. The work shall be done by a third party consultant
agreeable to both parties over a five day sampling period with each
location sampled per day. The sampling locations shall be as follows:
1) Upwind of Tank Battery
2) Downwind of Tank Battery
3) City Park
4) One location downtown, such as New Belgium Brewery
or Wild Boar Coffee
i) One Time Air Sampling During Well Completion – The Company
D. Pits. Pits constructed after May 1, 2009 on federal land or after April 1, 2009
on all other land with a potential to emit VOC of five (5) tpy or greater and
located in Garfield, Mesa, or Rio Blanco County shall not be located within 1/4
mile of a building unit, educational facility, assembly building, hospital, nursing
home, board and care facility, jail, or designated outside activity area. For the
purposes of this section, compliance with Rule 902.c shall be considered a
required practice. Operators may provide site‐specific data and analyses to
COGCC staff establishing that pits potentially subject to this subsection do not
have a potential to emit VOC of five (5) tpy or greater.
E. Pneumatic Devices. In instances when new, replaced, or repaired pneumatic
devices are installed, low or no bleed valves must be used, where technically
feasible.
(3) Well completions.
A. Green completion practices are required on oil and gas wells where reservoir
pressure, formation productivity, and wellbore conditions are likely to enable
the well to be capable of naturally flowing hydrocarbon gas in flammable or
greater concentrations at a stabilized rate in excess of five hundred (500) MCFD
to the surface against an induced surface backpressure of five hundred (500)
psig or sales line pressure, whichever is greater. Green completion practices are
not required for exploratory wells, where the wells are not sufficiently
proximate to sales lines, or where green completion practices are otherwise not
technically and economically feasible.
B. Green completion practices shall include, but not be limited to, the following
emission reduction measures:
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shall conduct air sampling during well completion. The work shall be
done by a third party consultant agreeable to both parties. This shall
be done over a five day sampling period with each location sampled
per day. The sampling shall be for one well completion in the City
(City’s choice of which well completion). The sampling locations shall
be as follows:
1) Upwind of well
2) Downwind of well
j) Ongoing Air Quality Monitoring ‐ Periodic air monitoring shall be
performed for hydrogen sulfide (H2S), a hazardous air pollutant
(HAP). The Company shall perform field monitoring using the Jerome
631 XC or equivalent instrument annually, or until such time that
odors are not detected past the Fort Collins Tank Battery fence line in
City Limits.
k) The City may require the Company to conduct additional air
monitoring as needed to respond to emergency events such as spill,
process upsets, or accidental releases or in response to odor
complaints in City Limits.
1) In response to emergency events that involve the
potential release of hazardous air pollutants, the Company may
be required to conduct air sampling in accordance with
subsection i above.
2) In response to odor complaints, the Company may be
required to conduct air sampling in accordance with subsection j
above or use a photo‐ionization detector (PID) to measure
detected levels of VOCs that exceed acute health‐based exposure
thresholds, or other air sampling methodology depending on the
nature of the complaint.
l) Air Quality Action Days. The Company shall respond to air quality
Action Day advisories posted by the Colorado Department of Public
Health and Environment for the Front Range Area by implementing
air emission reduction measures committed to in the Air Quality
iii. Well effluent containing more than ten (10) barrels per day of
condensate or within two (2) hours after first encountering hydrocarbon gas
of salable quality shall be directed to a combination of sand traps,
separators, surge vessels, and tanks or other equipment as needed to
ensure safe separation of sand, hydrocarbon liquids, water, and gas and to
ensure salable products are efficiently recovered for sale or conserved and
that non‐salable products are disposed of in a safe and environmentally
responsible manner.
iv. If it is safe and technically feasible, closed‐top tanks shall utilize
backpressure systems that exert a minimum of four (4) ounces of
backpressure and a maximum that does not exceed the pressure rating of
the tank to facilitate gathering and combustion of tank vapors.
Vent/backpressure values, the combustor, lines to the combustor, and
knock‐outs shall be sized and maintained so as to safely accommodate any
surges the system may encounter.
v. All salable quality gas shall be directed to the sales line as soon as
practicable or shut in and conserved. Temporary flaring or venting shall be
permitted as a safety measure during upset conditions and in accordance
with all other applicable laws, rules, and regulations.
C. An operator may request a variance from the Director if it believes that
employing green completion practices is not feasible because of well or field
conditions or that following them in a specific instance would endanger the
safety of well site personnel or the public.
D. In instances where green completion practices are not technically feasible or
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Mitigation Plan. Emission reduction measures shall be implemented
for the duration of an air quality Action Day advisory and may include
measures such as:
1) Minimize vehicle and engine idling
2) Reduce truck traffic and worker traffic
3) Delay vehicle refueling
4) Suspend or delay use of fossil fuel powered ancillary
equipment
5) Postpone construction activities
22. Green completions.
a) Gas gathering lines, separators, and sand traps capable of supporting
green completions as described in COGCC Rule 805 shall be installed at
any location at which commercial quantities of gas are reasonably
expected to be produced based on existing adjacent wells within one (1)
mile or well.
b) Uncontrolled venting is prohibited.
c) Temporary flowback flaring and oxidizing equipment shall include
the following:
1) Adequately sized equipment to handle 1.5 times the largest
flowback volume of gas experienced in a ten (10) mile radius
producing from the same formation;
2) Valves and porting available to divert gas to flaring and oxidizing
equipment; and
3) Auxiliary fueled with sufficient supply and heat to combust or
oxidize non‐combustible gases in order to control odors and
hazardous gases. The flowback combustion device shall be equipped
with a reliable continuous ignition source over the duration of
flowback, except in conditions that may result in a fire hazard or
explosion.
4) The Company has a general duty to safely maximize resource
recovery and minimize releases to the atmosphere during flowback
and subsequent recovery/operation.
(New Rules)
Rule 805.b. (3) Well completions.
A. Green completion practices are required on oil and gas wells where reservoir
pressure, formation productivity, and wellbore conditions are likely to enable the
well to be capable of naturally flowing hydrocarbon gas in flammable or greater
concentrations at a stabilized rate in excess of five hundred (500) MCFD to the
surface against an induced surface backpressure of five hundred (500) psig or
sales line pressure, whichever is greater. Green completion practices are not
required for exploratory wells, where the wells are not sufficiently proximate to
sales lines, or where green completion practices are otherwise not technically and
economically feasible.
B. Green completion practices shall include, but not be limited to, the following
emission reduction measures:
i. The operator shall employ sand traps, surge vessels, separators, and tanks
as soon as practicable during flowback and cleanout operations to safely
maximize resource recovery and minimize releases to the environment.
ii. Well effluent during flowback and cleanout operations prior to
encountering hydrocarbon gas of salable quality or significant volumes of
condensate
may be directed to tanks or pits (where permitted) such that oil or condensate
volumes shall not be allowed to accumulate in excess of twenty (20) barrels
and must be removed within twenty‐four (24) hours.
The gaseous phase of non‐flammable effluent may be directed to a flare pit or
vented from tanks for safety purposes until flammable gas is encountered.
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quality shall be directed to a combination of sand traps, separators, surge
vessels, and tanks or other equipment as needed to ensure safe separation of
sand, hydrocarbon liquids, water, and gas and to ensure salable products are
efficiently recovered for sale or conserved and that non‐salable products are
disposed of in a safe and environmentally responsible manner.
iv. If it is safe and technically feasible, closed‐top tanks shall utilize
backpressure systems that exert a minimum of four (4) ounces of
backpressure and a maximum that does not exceed the pressure rating of the
tank to facilitate gathering and combustion of tank vapors.
Vent/backpressure values, the combustor, lines to the combustor, and knock‐
outs shall be sized and maintained so as to safely accommodate any surges
the system may encounter.
v. All salable quality gas shall be directed to the sales line as soon as
practicable or shut in and conserved. Temporary flaring or venting shall be
permitted as a safety measure during upset conditions and in accordance with
all other applicable laws, rules, and regulations.
C. An operator may request a variance from the Director if it believes that using
green completion practices is infeasible due to well or field conditions, or would
endanger the safety of wellsite personnel or the public.
D. In instances where green completion practices are not technically feasible,
operators shall employ Best Management Practices (BMPs) to reduce emissions.
Such BMPs shall consider safety and shall include measures or actions to minimize
the time period during which gases are emitted directly to the atmosphere, and
monitoring and recording the volume and time period of such emissions.
23. Exhaust. The exhaust from all engines, motors, coolers and other
mechanized equipment shall be vented up or in a direction away from the
closest existing residences.
802.e. Exhaust from all engines, motors, coolers and other mechanized equipment
shall be vented in a direction away from all building units.
24. Fencing. Permanent perimeter fencing shall be installed around
production equipment, and shall be secured. The main purpose of the
fencing is to deter entrance by unauthorized people. The Company shall
use visually interesting fencing, when feasible, but the parties recognize
that there is a need for air circulation, and for the field personnel who
regularly inspect the facilities to be able to identify visual operational
deficiencies when driving by. Landscaping may be used for screening. If a
chain link fence is required to achieve safety requirements set by the
Rule 604.c.2.M
Fencing requirements. Unless otherwise requested by the Surface Owner, well sites
constructed within Designated Setback Locations, shall be adequately fenced to
restrict access by unauthorized persons.
1002. SITE PREPARATION AND STABILIZATION
a. Effective June 1, 1996:
(1) Fencing of drill sites and access roads on crop lands. During drilling operations
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COGCC, then landscaping and other screening mechanisms shall be
required that comply with the City’s Land Use Code regulations and the
Company’s safety requirements.
on crop lands, when requested by the surface owner, the operator shall delineate
each drillsite and access road on crop lands constructed after such date by berms,
single strand fence, or other equivalent method in order to discourage
unnecessary surface disturbances.
(2) Fencing of reserve pit when livestock is present. During drilling operations
where livestock is in the immediate area and is not fenced out by existing fences,
the operator, at the request of the surface owner, will install a fence around the
reserve pit.
(3) Fencing of well sites. Subsequent to drilling operations, where livestock is in
the immediate area and is not fenced out by existing fences, the operator, at the
request of the surface owner, will install a fence around the wellhead, pit, and
production equipment to prevent livestock entry.
25. Flammable material. All land within twenty five (25) feet of any tank,
or other structure containing flammable or combustible materials shall be
kept free of dry weeds, grass or rubbish, and will conform to Section 315
of the International Fire Code.
Staff did not find COGCC regulations addressing flammable materials.
26. Floodplains. All oil and gas operations shall comply with Chapter 10
of the City Code.
Oil and gas operations are allowed in floodplains. The following rules apply to
floodplains:
603.k. Statewide equipment anchoring requirements. All equipment at drilling and
production sites in geological hazard and floodplain areas shall be anchored to the
extent necessary to resist flotation, collapse, lateral movement, or subsidence.
Rule 1005d. Requires special drilling pit closures within the 100‐year floodplain (see
the 900 Series).
Rule 1204.a.4 Establish new staging, refueling, and chemical storage areas outside
of riparian zones and floodplains.
27. Water Quality Monitoring Plan. The Company shall comply with
COGCC Rule 609. In summary, this requires pre‐ and post‐drilling testing.
The rules require oil and gas operators to sample all “Available Water
Sources” (owner has given consent for sampling and testing and has
consented to having the sample data obtained made available to the
public), with a cap of four (4) water sources, within one‐half (1/2) mile
radius of a proposed well, multi‐well site, or dedicated injection well.
Water sources include registered water wells, permitted or adjudicated
Rule 609 (Statewide Groundwater Baseline Sampling and Monitoring):
a. Applicability and effective date.
(1) This Rule 609 applies to Oil Wells, Gas Wells (hereinafter, Oil and Gas Wells),
Multi‐Well Sites, and Dedicated Injection Wells as defined in the 100‐ Series Rules,
for which a Form 2 Application for Permit to Drill is submitted on or after May 1,
2013.
(2) This Rule 609 does not apply to an existing Oil or Gas Well that is repermitted
for use as a Dedicated Injection Well.
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springs, and certain monitoring wells. The Company agrees to the
following requirements above and beyond the COGCC requirements:
analyzing for dissolved metals as indicated in the Land Use Code; and
sampling intervals to be baseline (before drilling), post‐drilling at one,
three, and six years. Analytical results shall be shared with the COGCC,
the City, and the landowner. All spills, for new and existing wells, shall be
managed in accordance with COGCC regulations.
(3) This rule does not apply to Oil and Gas Wells, Multi‐Well Sites, or Dedicated
Injection Wells that are regulated under Rule 608.b., Rule 318A.e.(4), or Orders of
the Commission with respect to the Northern San Juan Basin promulgated prior to
the effective date of this Rule that provide for groundwater testing.
(4) Nothing in this Rule is intended, and shall not be construed, to preclude or
limit the Director from requiring groundwater sampling or monitoring at other
Production Facilities consistent with other applicable Rules, including but not
limited to the Oil and Gas Location Assessment process, and other processes in
place under 900‐series E&P Waste Management Rules (Form 15, Form 27, Form
28).
(5) An operator may elect to install one or more groundwater monitoring wells to
satisfy, in full or in part, the requirements of Rule 609.b., but installation of
monitoring wells is not required under this Rule.
b. Sampling locations. Initial baseline samples and subsequent monitoring samples
shall be collected from all Available Water Sources, up to a maximum of four (4),
within a one‐half (1/2) mile radius of a proposed Oil and Gas Well, Multi‐Well Site,
or Dedicated Injection Well. If more than four (4) Available Water Sources are
present within a one‐half (1/2) mile radius of a proposed Oil and Gas Well, Multi‐
Well Site, or Dedicated Injection Well, the operator shall select the
four sampling locations based on the following criteria:
(1) Proximity. Available Water Sources closest to the proposed Oil or Gas Well, a
Multi‐Well Site, or Dedicated Injection Well are preferred.
(2) Type of Water Source. Well maintained domestic water wells are preferred
over other Available Water Sources.
(3) Orientation of sampling locations. To extent groundwater flow direction is
known or reasonably can be inferred, sample locations from both downgradient
and up‐gradient are preferred over cross‐gradient locations.
Where groundwater flow direction is uncertain, sample locations should be
chosen in a radial pattern from a proposed Oil and Gas Well, Multi‐Well Site, or
Dedicated Injection Well.
(4) Multiple identified aquifers available. Where multiple defined aquifers are
present, sampling the deepest and shallowest identified aquifers is preferred.
(5) Condition of Water Source. An operator is not required to sample Water
Sources that are determined to be improperly maintained, nonoperational, or
have other physical impediments to sampling that would not allow for a
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representative sample to be safely collected or would require specialized sampling
equipment (e.g. shut‐in wells, wells with confined space issues, wells with no tap
or pump, non‐functioning wells, intermittent springs).
c. Inability to locate an Available Water Source. Prior to spudding, an operator may
request an exception from the requirements of this Rule 609 by filing a Form 4
Sundry Notice for the Director’s review and approval if:
(1) No Available Water Sources are located within one‐half (1/2) mile of a
proposed Oil and Gas Well, Multi‐Well Site, or Dedicated Injection Well;
(2) The only Available Water Sources are determined to be unsuitable pursuant to
subpart b.5, above. An operator seeking an exception on this ground shall
document the condition of the Available Water Sources it has deemed
unsuitable; or
(3) The owners of all Water Sources suitable for testing under this Rule refuse to
grant access despite an operator’s reasonable good faith efforts to obtain consent
to conduct sampling. An operator seeking an exception on this ground shall
document the efforts used to obtain access from the owners of suitable Water
Sources.
(4) If the Director takes no action on the Sundry Notice within ten (10) business
days of receipt, the requested exception from the requirements of this Rule 609
shall be deemed approved.
d. Timing of sampling.
(1) Initial sampling shall be conducted within 12 months prior to setting conductor
pipe in a Well or the first Well on a Multi‐Well Site, or commencement of drilling a
Dedicated Injection Well; and
(2) Subsequent monitoring: One subsequent sampling event shall be conducted at
the initial sample locations between six (6) and twelve (12) months, and a second
subsequent sampling event shall be conducted between sixty (60) and seventy‐
two (72) months following completion of the Well or Dedicated Injection Well, or
the last Well on a Multi‐Well Site. Wells that are drilled and abandoned without
ever producing hydrocarbons are exempt from subsequent monitoring sampling
under this subpart d.
(3) Previously sampled Water Sources. In lieu of conducting the initial sampling
required pursuant to subjection d.(1) or the second subsequent sampling event
required pursuant to subsection d.(2), an Operator may rely on water sampling
analytical results obtained from an Available Water Source within the sampling
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area provided:
A. The previous water sample was obtained within the 18 months preceding
the initial sampling event required pursuant to subsection d.(1) or the second
subsequent sampling event required pursuant to subsection d.(2); and
B. the sampling procedures, including the constituents sampled for, and the
analytical procedures used for the previous water sample were substantially
similar to those required pursuant to subparts e.(1) and (2), below. An
operator may not rely solely on previous water sampling
analytical results obtained pursuant to the subsequent sampling requirements
of subsection d.(2), above, to satisfy the initial sampling requirement of
subsection d.(1); and
C. the Director timely received the analytical data from the previous sampling
event.
(4) The Director may require additional sampling if changes in water quality are
identified during subsequent monitoring.
e. Sampling procedures and analysis.
(1) Sampling and analysis shall be conducted in conformance with an accepted
industry standard as described in Rule 910.b.(2). A model Sampling and
Analysis Plan (“COGCC Model SAP”) shall be posted on the COGCC website, and
shall be updated periodically to remain current with evolving industry standards.
Sampling and analysis conducted in conformance with the COGCC Model SAP shall
be deemed to satisfy the requirements of this subsection f.(1). Upon request, an
operator shall provide its sampling protocol to the Director.
(2) The initial baseline testing described in this section shall include pH, specific
conductance, total dissolved solids (TDS), dissolved gases (methane, ethane,
propane), alkalinity (total bicarbonate and carbonate as CaCO3), major anions
(bromide, chloride, fluoride, sulfate, nitrate and nitrite as N, phosphorus), major
cations (calcium, iron, magnesium, manganese, potassium, sodium), other
elements (barium, boron, selenium and strontium), presence of bacteria (iron
related, sulfate reducing, slime forming), total petroleum hydrocarbons (TPH) and
BTEX compounds (benzene, toluene, ethylbenzene and xylenes). Field
observations such as odor, water color, sediment, bubbles, and effervescence
shall also be documented. The location of the sampled Water Sources shall be
surveyed in accordance with Rule 215.
(3) Subsequent sampling to meet the requirements of subpart d.(2) shall include
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total dissolved solids (TDS), dissolved gases (methane, ethane, propane), major
anions (bromide, chloride, sulfate, and fluoride), major cations (potassium,
sodium, magnesium, and calcium), alkalinity (total bicarbonate and carbonate as
CaCO3), BTEX compounds (benzene, toluene, ethylbenzene and xylenes), and TPH.
(4) If free gas or a dissolved methane concentration greater than 1.0 milligram per
liter (mg/l) is detected in a water sample, gas compositional analysis and stable
isotope analysis of the methane (carbon and hydrogen – 12C, 13C, 1H and 2H)
shall be performed to determine gas type. The operator shall notify the Director
and the owner of the water well immediately if:
A. the test results indicated thermogenic or a mixture of thermogenic and
biogenic gas;
B. the methane concentration increases by more than 5.0 mg/l between
sampling periods; or
C. the methane concentration is detected at or above 10 mg/l.
(5) The operator shall notify the Director immediately if BTEX compounds or TPH
are detected in a water sample.
f. Sampling Results. Copies of all final laboratory analytical results shall be provided
to the Director and the water well owner or landowner within three (3) months of
collecting the samples. The analytical results, the surveyed sample
Water Source locations, and the field observations shall be submitted to the
Director in an electronic data deliverable format.
(1) The Director shall make such analytical results available publicly by posting on
the Commission’s web site or through another means announced to the public.
(2) Upon request, the Director shall also make the analytical results and surveyed
Water Source locations available to the Local Governmental Designee from the
jurisdiction in which the groundwater samples were collected, in the same
electronic data deliverable format in which the data was provided to the Director.
g. Liability. The sampling results obtained to satisfy the requirements of this Rule
609, including any changes in the constituents or concentrations of constituents
present in the samples, shall not create a presumption of liability, fault, or causation
against the owner or operator of a Well, Multi‐Well Site, or Dedicated Injection Well
who conducted the sampling, or on whose behalf sampling was conducted by a
third‐party. The admissibility and probity of any such sampling results in an
administrative or judicial proceeding shall be determined by the presiding body
according to applicable administrative, civil, or evidentiary rules.
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28. Landscaping. In the Fort Collins Field, existing Well Pads shall be used
for any New Wells and all landscaping shall be in compliance with the City
of Fort Collins Land Use Code standards and in compliance with the safety
requirements of the Company. Existing vegetation shall be minimally
impacted. In the UDA, motorized equipment shall be restricted to the
Well Pad and access roads to the Well Pads. A Visual Mitigation Plan,
along with fencing and landscaping, shall be developed for new
construction.
804. VISUAL IMPACT MITIGATION
Production facilities, regardless of construction date, which are observable from any
public highway shall be painted with uniform, non‐contrasting, non‐reflective color
tones (similar to the Munsell Soil Color Coding System), and with colors matched to
but slightly darker than the surrounding landscape by September 1, 2010.
Restoration and revegetation standards require post‐production revegetation (Rule
1003.e and 1004.c)
29. Lighting. Except during drilling, completion or other operational
activities requiring additional lighting, down‐lighting is required, meaning
that all bulbs must be fully shielded to prevent light emissions above a
horizontal plane drawn from the bottom of the fixture. A lighting plan
shall be developed to establish compliance with this provision. The
lighting plan shall indicate the location of all outdoor lighting on the site
and any structures, and include cut sheets (manufacturer's specifications
with picture or diagram) of all proposed fixtures.
803. LIGHTING
To the extent practicable, site lighting shall be directed downward and internally so
as to avoid glare on public roads and building units within seven (700) hundred feet.
30. Maintenance of machinery. Routine field maintenance of vehicles
or mobile machinery shall not be performed within three hundred (300)
feet of any water body.
The COGCC must first make a determination if an area is a “sensitive area;” only
then will special requirements be triggered, such as increased requirements on
Exploration and Production Waste Management, e.g., a leak detection system. Staff
did not find COGCC regulations requiring machines to be maintained outside of a
300’ buffer zone from a water body.
31. Mud Tracking. The Company shall take all practicable measures to
ensure that vehicles do not track mud or debris onto City streets. If mud
or debris is nonetheless deposited on City streets, the streets shall be
cleaned immediately by the Company using pressured water from a
water truck. This shall be done as part of maintenance. If for some
reason it cannot be done, or needs to be postponed, the LGD shall be
notified of the Company’s plan for mud removal.
Staff did not find COGCC regulations addressing mud tracking.
32. Natural Resources. An Ecological Characterization Study shall be
provided if any New Well is within 500 feet of a Natural Habitat or
Feature, and if impacting these resources, mitigation plans to ensure no
net resource loss per Fort Collins Land Use Code 3.4.1.
Rule 1201 and 1203 – The state requires certain regulations for operating within
sensitive natural areas, all of which would apply to Prospect Energy, e.g., the
requirement to install wildlife crossovers if open trenches are left open for more
than 5 days and are greater than 5’ in width, can also trigger consultation with the
Division of Parks and Wildlife.
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33. Noise mitigation. Noise mitigation measures shall be constructed
along any edge of any oil and gas operation site if such edge is between
the oil and gas operation and existing residential development or land
which is zoned for future residential development. The noise mitigation
measures shall, to the maximum extent feasible, decrease noise from the
oil and gas operations to comply with the sound limitation regulations set
forth in Commission Rule 802. A noise mitigation study shall be
submitted with the application to demonstrate that noise shall be
decreased to the maximum extent feasible.
Rule 802 The type of land use of the surrounding area shall be determined by the
Director in consultation with the Local Governmental Designee taking into
consideration any applicable zoning or other local land use designation. In the hours
between 7:00 a.m. and the next 7:00 p.m. the noise levels permitted above may be
increased ten (10) dB(A) for a period not to exceed fifteen (15) minutes in any one
(1) hour period. The allowable noise level for periodic, impulsive or shrill noises is
reduced by five (5) dB (A) from the levels shown.
ZONE 7:00 am to
next 7:00 pm
7:00 pm
to next
7:00 am
Residential/
Agricultural/Rural
55 db(A) 50 db(A)
Commercial 60 db(A) 55 db(A)
Light industrial 70 db(A) 65 db(A)
Industrial 80 db(A) 75 db(A)
Rule 802.e Exhaust from all engines, motors, coolers and other mechanized
equipment shall be vented in a direction away from all building units.
34. Pipelines. Any newly constructed or substantially modified pipelines
on site shall meet the following requirements:
(a) To the maximum extent feasible, all flow lines, gathering lines, and
transmission lines shall be sited a minimum of fifty (50) feet away
from general residential, commercial, and industrial buildings, as well
as the high‐water mark of any surface water body. This distance shall
be measured from the nearest edge of the pipeline. Pipelines and
gathering lines that pass within 150 feet of general residential,
commercial, and industrial buildings or the high water mark of any
surface water body shall incorporate leak detection, secondary
containment, or other mitigation, as appropriate.
(b) To the maximum extent feasible, pipelines shall be aligned with
established roads in order to minimize surface impacts and reduce
habitat fragmentation and disturbance.
(c) To the maximum extent feasible, operators shall share existing
In the Greater Wattenberg Area, the COGCC does encourage new operations to
collocate with existing production facilities (Rule 318A(5)).
The COGCC does require that “In order to reasonably minimize land disturbances
and facilitate future reclamation, well sites, production facilities, gathering pipelines,
and access roads shall be located, adequately sized, constructed, and maintained so
as to reasonably control dust and minimize erosion, alteration of natural features,
removal of surface materials, and degradation due to contamination.” (Rule
1000.2.e).
Rules 1101‐1103 cover the installation, reclamation and abandonment of pipelines.
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pipeline rights‐of‐way and consolidate new corridors for pipeline
rights‐of‐way to minimize surface impacts.
(d) To the maximum extent feasible, operators shall use boring
technology when crossing streams, rivers, or irrigation ditches with a
pipeline to minimize negative impacts to the channel, bank, and
riparian areas.
35. Recordation of flowlines. All new flowlines, including transmission
and gathering systems, shall have the legal description of the location
recorded with the City Clerk and the Larimer County Clerk and Recorder
within thirty (30) days of completion of construction. Abandonment of
any recorded flowlines shall be recorded with the Larimer County Clerk
and Recorder’s office within thirty (30) days after abandonment.
Staff did not find COGCC regulations addressing recordation of flowlines.
36. Recreational Activity Standards. The installation and operation of
any oil and gas operation shall not cause significant degradation to the
quality and quantity of recreational activities in the City. Methods to
achieve compliance with this standard include, but are not limited to
locating operations away from trails and from property used for
recreational purposes, or by using existing Well Pads.
The COGCC requires setbacks only for areas identified as “designated outside
activity areas.” If an area is formally designated, then the same setback provisions
and rules that apply in high density areas applies to these recreational areas.
37. Removal of debris. When an oil and gas operation becomes
operational, all construction‐related debris shall be removed from the site
for proper disposal. The site shall be maintained free of debris and excess
materials at all times during operation. Materials shall not be buried or
burned on‐site.
1003.a. General. Debris and waste materials other than de minimis amounts,
including, but not limited to, concrete, sack bentonite and other drilling mud
additives, sand plastic, pipe and cable, as well as equipment associated with the
drilling, re‐entry, or completion operations shall be removed. All E&P waste shall be
handled according to the 900 Series rules. All pits, cellars, rat holes, and other bore
holes unnecessary for further lease operations, excluding the drilling pit, will be
backfilled as soon as possible after the drilling rig is released to conform with
surrounding terrain. On crop land, if requested by the surface owner, guy line
anchors shall be removed as soon as reasonably possible after the completion rig is
released. When permanent guy line anchors are installed, it shall not be mandatory
to remove them. When permanent guy line anchors are installed on cropland, care
shall be taken to minimize disruption or cultivation, irrigation, or harvesting
operations. If requested by the surface owner or its representative, the anchors
shall be specifically marked, in addition to the marking required below, so as to
facilitate farming operations. All guy line anchors left buried for future use shall be
identified by a marker of bright color not less than four (4) feet in height and not
greater than one (1) foot east of the guy line anchor. In addition, all well sites and
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surface production facilities shall be maintained in accordance with Rule 603.j.
38. Removal of equipment. All equipment used for drilling, re‐
completion and maintenance of the facility shall be removed from the
site within thirty (30) days of completion of the work, unless otherwise
agreed to by the surface owner. Permanent storage of equipment on
Well Pad sites shall not be allowed.
See above for rule 1003.a.
39. Soil Gas Monitoring. The City, at its discretion, may conduct soil gas
monitoring to assess well casing integrity. This shall be typically
completed within ninety (90) days of New Well completion. The City shall
notify the Company prior to entering the site for soil gas monitoring.
Soil gas monitoring is only required by the COGCC in the case of coalbed methane
exploration.
40. Spills. The Company shall comply with COGCC Rule 906“Spills and
Releases”, and notify the City and whenever there is notification to the
COGCC. The Company shall also copy the City on any written
correspondence to the COGCC or other regulatory authority.
The City also requires in the Emergency Response section that the Office
of Emergency Management and Poudre Fire Authority may require
notification of spills less than 5 barrels (current COGCC requirements)
depending on the type of spill.
906. SPILLS AND RELEASES
a. General. Spills/releases of E&P waste, including produced fluids, shall be
controlled and contained immediately upon discovery to protect the environment,
public health, safety, and welfare, and wildlife resources. Impacts resulting from
spills/releases shall be investigated and cleaned up as soon as practicable. The
Director may require additional activities to prevent or mitigate threatened or
actual significant adverse environmental impacts on any air, water, soil or biological
resource, or to the extent necessary to ensure compliance with the concentration
levels in Table 910‐1, with consideration to WQCC ground water standards and
classifications.
b. Reportable spills and reporting requirements for spills/releases.
(1) Spills/releases of E&P waste or produced fluid exceeding five (5) barrels,
including those contained within lined or unlined berms, shall be reported on
COGCC Spill/Release Report, Form 19.
(2) Spills/releases which exceed twenty (20) barrels of an E&P waste shall be
reported on COGCC Spill/Release Report, Form 19, and shall also be verbally
reported to the Director as soon as practicable, but not more than twenty‐four
(24) hours after discovery.
(3) Spills/releases of any size which impact or threaten to impact any waters of
the state, residence or occupied structure, livestock, or public byway shall be
reported on COGCC Spill/Release Report, Form 19, and shall also be verbally
reported to the Director as soon as practicable, but not more than twenty‐four
(24) hours, after discovery.
(4) Spills/releases of any size which impact or threaten to impact any surface
water supply area shall be reported to the Director and to the Environmental
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Release/Incident Report Hotline (1‐877‐518‐5608). Spills and releases that impact
or threaten a surface water intake shall be verbally reported to the emergency
contact for that facility immediately after discovery.
(5) For all reportable spills, operators shall submit a Spill/Release Report, Form
19, within ten (10) days after discovery. An 8 1/2 x 11 inch topographic map
showing the governmental section and location of the spill shall be included. Such
report shall also include information relating to initial mitigation, site
investigation, and remediation. The Director may require additional information.
(6) Chemical spills and releases shall be reported in accordance with applicable
state and federal laws, including the Emergency Planning and Community Right‐
to‐Know Act, the Comprehensive Environmental Response, Compensation, and
Liability Act, the Oil Pollution Act, and the Clean Water Act, as applicable.
c. Surface owner notification and consultation. The operator shall notify the
affected surface owner or the surface owner’s appointed tenant of reportable spills
as soon as practicable, but not more than twenty‐four (24) hours, after discovery.
The operator also shall make good faith efforts to notify and consult with the
affected surface owner, or the surface owner’s appointed tenant, prior to
commencing operations to remediate E&P waste from a spill/release in an area not
being utilized for oil and gas operations.
d. Remediation of spills/releases. When threatened or actual significant adverse
environmental impacts on any air, water, soil or other environmental resource from
a spill/release exists or when necessary to ensure compliance with the
concentration levels in Table 910‐1, with consideration to WQCC ground water
standards and classifications, the Director may require operators to submit a Site
Investigation and Remediation Workplan, Form 27. Such spills/releases shall be
remediated in accordance with Rules 909. and 910.
e. Spill/release prevention.
(1) Secondary containment. Secondary containment that was constructed before
May 1, 2009 on federal land, or before April 1, 2009 on other land, shall comply
with the rules in effect at the time of construction. Secondary containment
constructed on or after May 1, 2009 on federal land, or on or after April 1, 2009
on other land shall be constructed or installed around all tanks containing oil,
condensate, or produced water with greater than 3,500 milligrams per liter (mg/l)
total dissolved solids (TDS) and shall be sufficient to contain the contents of the
largest single tank and sufficient freeboard to contain precipitation. Secondary
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 31
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
containment structures shall be sufficiently impervious to contain discharged
material. Operators are also subject to tank and containment requirements under
Rules 603. and 604. This requirement shall not apply to water tanks with a
capacity of fifty (50) barrels or less.
(2) Spill/release evaluation. Operators shall determine the cause of a
spill/release, and, to the extent practicable, shall implement measures to prevent
spills/releases due to similar causes in the future. For reportable spills, operators
shall submit this information to the Director on the Spill/Release Report, Form
19, within ten (10) days after discovery of the spill/release.
41. Stormwater control plan. All oil and gas operations shall comply and
conform with the Fort Collins Storm Criteria Manual (FCSCM), including
submission of an Erosion Control Report and Plan.
Rule 1002.f f. Stormwater management.
(1) All oil and gas locations are subject to the Best Management Practices
requirements of Rule 1002.f.(2). In addition, upon the termination of a construction
stormwater permit issued by the Colorado Department of Public Health and
Environment for an oil and gas location, such oil and gas location is subject to the
Post‐Construction Stormwater Program requirements of Rule 1002.f.(3), except that
such requirements are not applicable to Tier 1 Oil and Gas Locations.
(2) Oil and gas operators shall implement and maintain Best Management Practices
(BMPs) at all oil and gas locations to control stormwater runoff in a manner that
minimizes erosion, transport of sediment offsite, and site degradation. BMPs shall
be maintained until the facility is abandoned and final reclamation is achieved
pursuant to Rule 1004. Operators shall employ BMPs, as necessary to comply with
this rule, at all oil and gas locations, including, but not limited to, well pads, soil
stock piles, access roads, tank batteries, compressor stations, and pipeline rights of
way. BMPs shall be selected based on site‐specific conditions, such as slope,
vegetation cover, and proximity to water bodies, and may include maintaining in‐
place some or all of the BMPs installed during the construction phase of the facility.
Where applicable based on site‐specific conditions, operators shall implement BMPs
in accordance with good engineering practices, including measures such as:
A. Covering materials and activities and stormwater diversion to minimize contact
of precipitation and stormwater runoff with materials, wastes, equipment, and
activities with potential to result in discharges causing pollution of surface
waters.
B. Materials handling and spill prevention procedures and practices implemented
for material handling and spill prevention of materials used, stored, or disposed
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 32
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
of that could result in discharges causing pollution of surface waters.
C. Erosion controls designed to minimize erosion from unpaved areas, including
operational well pads, road surfaces and associated culverts, stream crossings,
and cut/fill slopes.
D. Self‐inspection, maintenance, and good housekeeping procedures and
schedules to facilitate identification of conditions that could cause breakdowns or
failures of BMPs. These procedures shall include measures for maintaining clean,
orderly operations and facilities and shall address cleaning and maintenance
schedules and waste disposal practices. In conducting inspections and
maintenance relative to stormwater runoff, operators shall consider seasonal
factors, such as winter snow cover and spring runoff from snowmelt, to ensure
site conditions and controls are adequate and in place to effectively manage
stormwater.
E. Spill response procedures for responding to and cleaning up spills. The
necessary equipment for spill cleanup shall be readily available to personnel. Spill
Prevention, Control, and Countermeasure plans incorporated by reference must
be identified in the Post‐Construction Stormwater Management Program
specified in Rule 1002.f.(3).
F. Vehicle tracking control practices to control potential sediment discharges
from operational roads, well pads, and other unpaved surfaces. Practices could
include road and pad design and maintenance to minimize rutting and tracking,
controlling site access, street sweeping or scraping, tracking pads, wash racks,
education, or other sediment controls.
(3) Operators of oil and gas facilities shall develop a Post‐Construction Stormwater
Program in compliance with this section no later than the time of termination of
stormwater permits issued by the Colorado Department of Public Health and
Environment for construction of oil and gas facilities.
A. The Post‐Construction Stormwater Program shall reflect good faith efforts by
operators to select and implement BMPs intended to serve the purposes of this
rule. BMPs shall be selected to address potential sources of pollution which may
reasonably be expected to affect the quality of discharges associated with the
ongoing operation of production facilities during the post‐construction and
reclamation operation of the facilities. Pollutant sources that must be addressed
by BMPs, if present, include:
i. Transport of chemicals and materials, including loading and unloading
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 33
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
operations;
ii. Vehicle/equipment fueling;
iii. Outdoor storage activities, including those for chemicals and additives;
iv. Produced water and drilling fluids storage;
v. Outdoor processing activities and machinery;
vi. Significant dust or particulate generating processes;
vii. Erosion and vehicle tracking from well pads, road surfaces, and pipelines;
viii. Waste disposal practices;
ix. Leaks and spills; and
x. Ground‐disturbing maintenance activities.
B. The Post‐Construction Stormwater Program shall be developed, supervised,
documented, and maintained by a qualified person(s) with training or prior work
experience specific to stormwater management. Employees and subcontractors
shall be trained to make them aware of the BMPs implemented and maintained
at the site and procedures for reporting needed maintenance or repairs.
Documentation shall include a description of the BMPs selected to ensure proper
implementation, operation, and maintenance.
C. Facility‐specific maps, installation specification, and implementation criteria
shall also be included when general operating procedures and descriptions are
not adequate to clearly describe the implementation and operation of BMPs.
42. Temporary access roads. Temporary access roads associated with oil
and gas operations shall be reclaimed and re‐vegetated to the original
state.
1002.a.(1) (1) Fencing of drill sites and access roads on crop lands. During drilling
operations on crop lands, when requested by the surface owner, the operator shall
delineate each drillsite and access road on crop lands constructed after such date by
berms, single strand fence, or other equivalent method in order to discourage
unnecessary surface disturbances.
1002.e(1) In order to reasonably minimize land disturbances and facilitate future
reclamation, well sites, production facilities, gathering pipelines, and access roads
shall be located, adequately sized, constructed, and maintained so as to reasonably
control dust and minimize erosion, alteration of natural features, removal of surface
materials, and degradation due to contamination.
1002.e(4) Access roads. Existing roads shall be used to the greatest extent
practicable to avoid erosion and minimize the land area devoted to oil and gas
operations. Roadbeds shall be engineered to avoid or minimize impacts to riparian
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 34
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
areas or wetlands to the extent practicable. Unavoidable impacts shall be mitigated.
Road crossings of streams shall be designed and constructed to allow fish passage,
where practicable and appropriate. Where feasible and practicable, operators are
encouraged to share access roads in developing a field. Where feasible and
practicable, roads shall be routed to complement other land usage. To the greatest
extent practicable, all vehicles used by the operator, contractors, and other parties
associated with the well shall not travel outside of the original access road
boundary. Repeated or flagrant instance(s) of failure to restrict lease access to lease
roads which result in unreasonable land damage or crop losses shall be subject to a
penalty under Rule 523.
Access roads are also addressed in Rule 603e.14 (regarding access roads
accommodating emergency vehicles in high density areas) and Rule 1004 (final
reclamation)
43. Trailers. A construction trailer or office is permitted as an accessory
use during active drilling and well completion only.
Staff did not find COGCC regulations addressing construction trailers.
44. Transportation and circulation. All applicants for drilling and
completion operations (New Wells) shall include in their applications
detailed descriptions of all proposed access routes for equipment, water,
sand, waste fluids, waste solids, mixed waste, and all other material to be
hauled on the public streets and roads of the City. The submittal shall
also include the estimated weights of vehicles when loaded, a description
of the vehicles, including the number of wheels and axles of such
vehicles, trips per day and any other information required by the Traffic
Engineer. Preliminary information is required for this item for the
Conceptual Review meeting, in accordance with Appendix B. The
Company shall comply with all Transportation and Circulation
requirements as contained in the Land Use Code as may be reasonably
required by the City’s Traffic Engineer.
Transportation is addressed in Rule 1203 by directing operators to “Reduce traffic
associated with transporting drilling water and produced liquids through the use of
pipelines, large tanks, or other measures where technically feasible and
economically practicable” (subsection 16) and in Rule 1204 by encouraging
operators to minimize impacts to wildlife in planning transportation networks.
Otherwise, transportation and circulation issues are left to local governments to
address.
45. Wastewater and Waste Management. In the Fort Collins Field, all
fluids shall be contained and there shall be no discharge of fluids, as
described in the Closed Loop System and Green Completions section of
this Appendix. Waste shall be stored in tanks, transported by tanker
trucks, and disposed of at licensed disposal fields. In the UDA, new
secondary containment shall be constructed of steel, with sufficient
Rule 900 series (approximately 17 pages long) allows for land treatment or disposal
of drilling muds.
A Spill Prevention, Control, and Countermeasure Plan is not required for facilities of
this size by COGCC.
ATTACHMENT 7
Operator Agreement – Comparison Matrix of the Operator Agreement to COGCC Regulations 35
Proposed Operator Agreement
Colorado Oil and Gas Conservation Commission Regulations
perimeter and height to hold one and one‐half (1.5) times the volume of
the largest tank and sufficient freeboard to prevent overflow. No
potential ignition sources shall be installed inside the secondary
containment area unless the containment enclosed a fired vessel. The
requirements for secondary containment will meet the Fort Collins
Stormwater Criteria Manual. No land treatment of oil impacted or
contaminated drill cuttings are permitted. The use of a closed loop
drilling system precludes discharge of produced water or flowback to the
ground or the use of pits. Produced water or flowback will not be used
for dust suppression. A copy of the field’s Spill Prevention, Control, and
Countermeasure Plan (SPCC) will be given to the City, which describes
spill prevention and mitigation practices. The Company will provide the
City documentation of waste disposal and its final disposition.
46. Water supply. The Company shall identify in the site plan its source
for water used in both the drilling and production phases of operations.
The sources and amount of water used in the City shall be documented
and this record shall be provided to the City annually or sooner, if
requested by the City Manager. The disposal of water used on site shall
also be detailed including anticipated haul routes, approximate number
of vehicles needed to supply and dispose of water and the final
destination for water used in operation.
No COGCC regulation applicable to water supply.
47. Weed control. The Company shall be responsible for ongoing weed
control at oil and gas operations, pipelines, and along access roads during
construction and operation, until abandonment and final reclamation is
completed per City, Larimer County or other applicable agency
regulations. The appropriate weed control methods and species to be
controlled shall be determined through review and recommendation by
the County Weed Coordinator by reference to the Larimer County
Noxious Weed Management Plan and in coordination with the
requirements of the surface owner.
1003.f. Weed control. During drilling, production, and reclamation operations, all
disturbed areas shall be kept as free of all undesirable plant species designated to
be noxious weeds as practicable. Weed control measures shall be conducted in
compliance with the Colorado Noxious Weed Act, C.R.S. §35‐5.5‐115 and the current
rules pertaining to the administration and enforcement of the Colorado Noxious
Weed Act. It is recommended that the operator consult with the local weed control
agency or other weed control authority when weed infestation occurs. It is the
responsibility of the operator to monitor affected and reclaimed lands for noxious
weed infestations. If applicable, the Director may require a weed control plan.
(Also see Rules 603j, 1002c, and 1003, and 1004 regarding weeds).
iii. Well effluent containing more than ten (10) barrels per day of condensate
or within two (2) hours after first encountering hydrocarbon gas of salable
are not required, operators shall employ Best Management Practices to reduce
emissions. Such BMPs may include measures or actions, considering safety, to
minimize the time period during which gases are emitted directly to the
atmosphere, or monitoring and recording the volume and time period of such
emissions. Such examples could include the flaring or venting of gas.
i. The operator shall employ sand traps, surge vessels, separators, and tanks
as soon as practicable during flowback and cleanout operations to safely
maximize resource recovery and minimize releases to the environment.
ii. Well effluent during flowback and cleanout operations prior to
encountering hydrocarbon gas of salable quality or significant volumes of
condensate may be directed to tanks or pits (where permitted) such that oil
or condensate volumes shall not be allowed to accumulate in excess of
twenty (20) barrels and must be removed within twenty‐four (24) hours.
The gaseous phase of non‐flammable effluent may be directed to a flare pit
or vented from tanks for safety purposes until flammable gas is
encountered.
within 1/4 mile of a building unit, educational facility, assembly building,
hospital, nursing home, board and care facility, jail, or designated outside
activity area shall utilize a control device capable of achieving 90% control
efficiency of VOC and shall hold a valid permit from the Colorado Department of
Public Health and Environment, Air Pollution Control Division, for the glycol
dehydrator and control device. Glycol dehydrators meeting the above criteria
and existing on May 1, 2009 on federal lands and on April 1, 2009 on all other
lands shall be in compliance with this subsection by October 1, 2009.
(1) Compliance.
A. Oil and gas operations shall be in compliance with the Department of Public
Health and Environment, Air Quality Control Commission, Regulation No. 2 Odor
Emission, 5 C.C.R. 1001‐4.
a. Setbacks. Effective August 1, 2013:
(1) Exception Zone Setback. No Well or Production Facility shall be located five
hundred (500) feet or less from a Building Unit except as provided in Rules
604.a.(1) A and B, and 604.b.
A. Urban Mitigation Areas. The Director shall not approve a Form 2A or
associated Form 2 proposing to locate a Well or a Production Facility within an
Exception Zone Setback in an Urban Mitigation Area unless:
i. the Operator submits a waiver from each Building Unit Owner within five
hundred (500) feet of the proposed Oil and Gas Location with the Form
Added requirement that a noise
mitigation plan must be submitted to
the City to illustrate how compliance
15
14
Same requirements as COGCC
3
1 baseline sampling event prior to site
construction
Increased to 3 post‐completion sampling
events at 1, 3, and 6 years after well
completion
1
Energy from the
moratorium and the
hydraulic fracturing
ban (5-1 vote).
On 4/16/13, the
second reading of the
ordinance to lift the
ban and exempt
Prospect Energy from
the moratorium was
postponed until
4/23/13.
An amended Operator
Agreement was
presented to Council
on 4/16/13; this item
was also postponed
until 4/23/13.
Prospect Energy Timeline
(to the best of our
understanding)
The Fort Collins Field has
been in operation since
1924. Prospect Energy (PE)
obtained ownership in 2009.
53 hydraulic fracturing
processes have occurred
since the 1950s.
When
moratorium
passes on 5/15,
Fort Collins Field
3rd Party sale falls
through.
Regulatory
environment
rating changes
from stable to
uncertain.
Prospect Energy is unable to develop their field
during the moratorium. Prospect Energy cannot
explore proved reserves or any other lease
holdings within the City.
Third party engineers inform Prospect Energy
that proved undeveloped (PUD’s) reserves will
be downgraded as per Securities and Exchange
Commission (SEC) guidelines due to regulatory
uncertainty at Fort Collins Field effective Q1
2013 for both financial books and for PE’s Bank
as per a Borrowing Base determination.
Prospect
Energy assets
devalued on
their financial
books effective
Q1 2013.
Staff receives
draft Operator
Agreement
from Prospect
Energy on
2/7/13.
After passage of the
ban, other mineral
royalty owners
affected (142 in Fort
Collins Field).
PE submits report to
the bank. Bank
write’s down Fort
Collins PUDs.
Informs bank that
negotiations are
ongoing.
Prospect Energy
Operator Agreement
remains on hold until
August 1 or when the
ban and moratorium
are lifted from their
fields.
Prospect Energy’s and
PE’s Bank is waiting on
final outcome of City
Council vote.