Colorado Regulations
The State of Colorado is a national leader in its commitment to fostering safe and responsible development of Colorado’s oil and gas resources. Colorado has implemented precedent setting regulations from baseline groundwater testing and monitoring and pipeline safety to air regulations targeting methane leak detection and repair. This is a summary of significant legislative and regulatory efforts affecting Colorado’s oil and gas industry.
Wellbore Integrity
A foundational element of COGCC regulations are those surrounding wellbore integrity (Series 300). These rules apply to the design and construction parameters for oil and natural gas wells and prevent the pollution of groundwater. They require ongoing monitoring, testing and reporting, and give the COGCC inspection authority throughout the life of a well to ensure that wellbore integrity is maintained.
Wells are constructed with multiple layers of steel casing and cement; COGCC rules require the following specifications for each well[1]:
[1] https://cogcc.state.co.us/documents/about/TF_Summaries/GovTaskForceSummary_Engineering%20Wellbore%20Integrity.pdf
[2] https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf
Wells are constructed with multiple layers of steel casing and cement; COGCC rules require the following specifications for each well[1]:
- In the water-bearing and hydrocarbon zones, the casing is cemented into place, and cement fills the void space between each layer of casing.
- At least two layers of steel casing and cement are in place from the ground surface to the lowest point of the freshwater aquifer.
- In the hydrocarbon formation, several thousand feet below the aquifer in most cases, there is at least one layer of steel and cement, and the hydrocarbons move through the inner-most casing to the surface.
[1] https://cogcc.state.co.us/documents/about/TF_Summaries/GovTaskForceSummary_Engineering%20Wellbore%20Integrity.pdf
[2] https://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf
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2011 - Hydraulic Fracturing Disclosure Rulemaking
On December 13, 2011, Colorado regulators unanimously passed a Hydraulic Fracturing Disclosure Rule that requires comprehensive public disclosure of the chemicals used in hydraulic fracturing treatments. The rule represents a balanced compromise between industry and environmental groups, providing transparency while protecting proprietary information.
Starting in April 2012, this rule (205A.) was applied to all hydraulically fractured treatments performed in Colorado[1]. The rules include public disclosure of hydraulic fracturing chemicals using FracFocus.org in addition to disclosure of the volume of water used and the concentration of chemicals in the hydraulic fracturing fluid.
This rule also requires operators to provide the Colorado Oil and Gas Conservation Commission (COGCC) with 48 hours prior notice before hydraulically fracturing a well. Operators must file their chemical registry form within 60 days of completing a hydraulic fracturing treatment.
This rule protects proprietary information by allowing operators to file a Form 41 for claimed trade secrets, however, in the case of an emergency, companies must disclose all ingredients to health care workers. Operators are still required to disclose information about chemical family when filing Form 41. The passage of this rule further demonstrates that Colorado’s oil and gas industry is committed to operating in a transparent and safe manner.
[1] http://cogcc.state.co.us/documents/reg/Rules/LATEST/200Series.pdf
Starting in April 2012, this rule (205A.) was applied to all hydraulically fractured treatments performed in Colorado[1]. The rules include public disclosure of hydraulic fracturing chemicals using FracFocus.org in addition to disclosure of the volume of water used and the concentration of chemicals in the hydraulic fracturing fluid.
This rule also requires operators to provide the Colorado Oil and Gas Conservation Commission (COGCC) with 48 hours prior notice before hydraulically fracturing a well. Operators must file their chemical registry form within 60 days of completing a hydraulic fracturing treatment.
This rule protects proprietary information by allowing operators to file a Form 41 for claimed trade secrets, however, in the case of an emergency, companies must disclose all ingredients to health care workers. Operators are still required to disclose information about chemical family when filing Form 41. The passage of this rule further demonstrates that Colorado’s oil and gas industry is committed to operating in a transparent and safe manner.
[1] http://cogcc.state.co.us/documents/reg/Rules/LATEST/200Series.pdf
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2013 - Baseline Water Quality Sampling Rulemaking
nIn January 2013, the COGCC approved the most rigorous statewide mandatory groundwater sampling and monitoring rules in the United States. The purpose of Rule 609, “is to gather baseline water quality data prior to oil and gas development occurring in a particular area, and to gather additional data after drilling and completion operations” (COGCC, 2013). Rule 609 was a national precedent setting rule and all data collected as part of this program is available to the general public through the COGCC database.
Under the rule operators are required to take water samples prior to, and after drilling. The monitoring samples are collected from 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.
Initial sampling must be conducted within 12 months prior to setting conductor casing or the commencement of drilling for a dedicated injection well. Subsequent samples are taken between 6-12 months after the initial sampling and 5-6 years following completion of the last well at a site.
*** Requirements in designated fields/regions may vary[1]
[1] See COGCC Rule 608.b. for Coalbed Methane Wells in the San Juan Basin
Under the rule operators are required to take water samples prior to, and after drilling. The monitoring samples are collected from 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.
Initial sampling must be conducted within 12 months prior to setting conductor casing or the commencement of drilling for a dedicated injection well. Subsequent samples are taken between 6-12 months after the initial sampling and 5-6 years following completion of the last well at a site.
*** Requirements in designated fields/regions may vary[1]
[1] See COGCC Rule 608.b. for Coalbed Methane Wells in the San Juan Basin
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2013 - Setback Rulemaking
On February 11, 2013, the Colorado Oil and Gas Conservation Commission (COGCC) voted to approve new Setback Rules to mitigate perceived effects of drilling near buildings.[1] The rules significantly increased setback distances and imposed advanced best management practices and protective measures to eliminate, minimize, or mitigate perceived impacts for all oil and gas locations within 1,000 feet of occupied buildings.
The adopted rules enhanced notice and communication with building owners within 1,000 feet of occupied buildings. The rules became effective in August 2013 and are viewed among the most protective in the nation.
These rules included the following setback distances:
[1]http://cogcc.state.co.us/announcements/hot_topics/setbacks/Definitions_Zones_Exceptions.pd
The adopted rules enhanced notice and communication with building owners within 1,000 feet of occupied buildings. The rules became effective in August 2013 and are viewed among the most protective in the nation.
These rules included the following setback distances:
- A uniform 500-foot statewide setback, applicable in both rural and urban areas
- A 1,000-foot setback from high occupancy buildings such as schools, nursing homes and hospitals.
[1]http://cogcc.state.co.us/announcements/hot_topics/setbacks/Definitions_Zones_Exceptions.pd
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2013 - Spills and Releases Rulemaking
In February 2014 the COGCC updated spill reporting requirements and tightened thresholds for reporting spills. Per COGCC rules, a spill is defined as any observable release of exploration and production (E&P) fluids or produced fluids spilled onsite which can include crude oil, condensate, salty water produced from a well, treatment fluids used during hydraulic fracturing, or diesel fuel used to power drilling rig generators. Rule 906 of the Colorado Oil and Gas Conservation Commission (COGCC) establishes requirements for spills and releases. Rule 906.a. requires operators investigate, clean up, and document impacts from spills to the COGCC and Rule 906.b. defines reportable spills and reporting requirements for spills/releases.
Under the rules updated in February 2014, an operator must report to the Director of the COGCC, verbally or in writing (within 24 hours of discovery), a spill or release in which one (1) barrel of more of E&P waste or produced fluids is spilled or released outside of berms or other secondary containment or a spill exceeding five (5) barrels within 24 hours after discovery.[1] The threshold under the previous rule was within 24 hours for twenty (20) barrels. Additionally, the term “produced fluids” was added to clarify that spills of oil, condensate, or natural gas liquids must be reported along with other exploration and production (E&P) waste. The other key change under amended rule 906.b. requires operators to report certain spills to the surface owner and local governments within 24 hours.
[1] http://cogcc.state.co.us/documents/reg/Rules/LATEST/900series.pdf
Under the rules updated in February 2014, an operator must report to the Director of the COGCC, verbally or in writing (within 24 hours of discovery), a spill or release in which one (1) barrel of more of E&P waste or produced fluids is spilled or released outside of berms or other secondary containment or a spill exceeding five (5) barrels within 24 hours after discovery.[1] The threshold under the previous rule was within 24 hours for twenty (20) barrels. Additionally, the term “produced fluids” was added to clarify that spills of oil, condensate, or natural gas liquids must be reported along with other exploration and production (E&P) waste. The other key change under amended rule 906.b. requires operators to report certain spills to the surface owner and local governments within 24 hours.
[1] http://cogcc.state.co.us/documents/reg/Rules/LATEST/900series.pdf
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2013 - Wildlife Map Update Rulemaking
In July of 2013, the COGCC initiated a rulemaking to update state wildlife maps. On September 17, 2013, the COGCC formally adopted rules updating Sensitive Wildlife Habitat Maps and Restricted Surface Occupancy Maps. (See 1200 series rules & Appendix VII-VIII).[1] These maps contain the ranges of species of interest to the state of Colorado. Specifically, these maps contain data about species range, habitat, and known migration patterns. When new data is available, these maps are updated, often in partnership with Colorado Parks and Wildlife (CPW).
Keeping these maps updated provides state regulators with information to ensure that sensitive species are appropriately accounted for through consultations required under Commission Rule 306.c. (see also Rule 1202).[2] These consultations occur between the COGCC, CPW, surface owner(s), and operators to “minimize adverse impacts” from proposed oil and gas development.
Of interest in this rulemaking were updates species specific definitions of Sensitive Wildlife Habitat for Mule deer critical winter range, Lesser Prairie Chicken focal areas, Greater Sage Grouse priority habitat, and Gunnison Sage Grouse production areas.
[1] http://cogcc.state.co.us/documents/reg/Rules/LATEST/1200Series.pdf
[2] http://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf
Keeping these maps updated provides state regulators with information to ensure that sensitive species are appropriately accounted for through consultations required under Commission Rule 306.c. (see also Rule 1202).[2] These consultations occur between the COGCC, CPW, surface owner(s), and operators to “minimize adverse impacts” from proposed oil and gas development.
Of interest in this rulemaking were updates species specific definitions of Sensitive Wildlife Habitat for Mule deer critical winter range, Lesser Prairie Chicken focal areas, Greater Sage Grouse priority habitat, and Gunnison Sage Grouse production areas.
[1] http://cogcc.state.co.us/documents/reg/Rules/LATEST/1200Series.pdf
[2] http://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf
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2014 - Air Emissions from Oil and Gas
On February 23, 2014, following a five-day public hearing, Colorado’s Air Quality Control Commission (AQCC) voted to adopt new precedent setting rules targeting air emissions from the oil and natural gas industry. These regulations fully adopted federal regulations (EPA’s NSPS OOOO) and added controls and strategies to reduce fugitive Volatile Organic Compounds (VOC’s) and hydrocarbon emissions from condensate tanks and other sources. This includes installation of emission control devices and implementation of leak detection and repair programs. These regulations became effective in the spring of 2014.[1]
Key elements of these air quality regulations include: leak detection and repair (LDAR), storage tank regulations, and expanded applicability to include pneumatic devices. The LDAR program is a tiered inspection requirement that requires operators to inspect components at natural gas compressor stations and well production facilities for leaks. The frequency of inspections for natural gas compressor stations is based on estimated VOC emissions. The frequency of inspections for well production facilities is based on whether or not equipment on site has emission reduction equipment (controlled) or does not have emission reduction equipment (uncontrolled). Newer facilities and most older facilities in Colorado will have controls in place for emissions.
Other provisions require storage tanks with uncontrolled VOC emissions ≥6 tons per year to control hydrocarbon emissions by 95%, and that all storage tanks utilized during the first 90 days of production must also reduce their emissions by 95%, unless total emissions are below a threshold of 1.5 tons during the first 90 days. Temporary frac tanks are excluded from this requirement. The rules create additional requirements for operating without venting during normal operation, audio, visual, and olfactory inspections, and the development of storage tank emissions management (STEM) plans.
The rules expanded the existing ozone non-attainment area requirements for auto-igniters and low bleed pneumatics to the rest of the state. They also require no-bleed (zero emission) pneumatics where electricity is available (in lieu of using gas). The rules also require the gas stream at well production facilities either be connected to a pipeline or routed to a control device from the date of first production. Other measures include more stringent control requirements for glycol dehydrators. Additionally, they require the use of best management practices to minimize the need for–and emissions from–well maintenance, as well as comprehensive recordkeeping and reporting requirements to help ensure transparent and accurate information.
At the time of the rulemaking, CDPHE estimated that these regulations would reduce VOC emissions by approximately 93,500 tons per year and would reduce methane/ethane emissions by approximately 65,000 tons per year. These rules ensure that all potential leaks at oil and natural gas facilities are controlled (reduced by 95% or greater) or are monitored and prevented through best management practices. Documentation and reporting was established so CDPHE could ensure compliance and allow for transparency to the public regarding the safety of air quality around oil and natural gas facilities.
[1] https://www.colorado.gov/pacific/cdphe/summary-oil-and-gas-emissions-requirements
Key elements of these air quality regulations include: leak detection and repair (LDAR), storage tank regulations, and expanded applicability to include pneumatic devices. The LDAR program is a tiered inspection requirement that requires operators to inspect components at natural gas compressor stations and well production facilities for leaks. The frequency of inspections for natural gas compressor stations is based on estimated VOC emissions. The frequency of inspections for well production facilities is based on whether or not equipment on site has emission reduction equipment (controlled) or does not have emission reduction equipment (uncontrolled). Newer facilities and most older facilities in Colorado will have controls in place for emissions.
Other provisions require storage tanks with uncontrolled VOC emissions ≥6 tons per year to control hydrocarbon emissions by 95%, and that all storage tanks utilized during the first 90 days of production must also reduce their emissions by 95%, unless total emissions are below a threshold of 1.5 tons during the first 90 days. Temporary frac tanks are excluded from this requirement. The rules create additional requirements for operating without venting during normal operation, audio, visual, and olfactory inspections, and the development of storage tank emissions management (STEM) plans.
The rules expanded the existing ozone non-attainment area requirements for auto-igniters and low bleed pneumatics to the rest of the state. They also require no-bleed (zero emission) pneumatics where electricity is available (in lieu of using gas). The rules also require the gas stream at well production facilities either be connected to a pipeline or routed to a control device from the date of first production. Other measures include more stringent control requirements for glycol dehydrators. Additionally, they require the use of best management practices to minimize the need for–and emissions from–well maintenance, as well as comprehensive recordkeeping and reporting requirements to help ensure transparent and accurate information.
At the time of the rulemaking, CDPHE estimated that these regulations would reduce VOC emissions by approximately 93,500 tons per year and would reduce methane/ethane emissions by approximately 65,000 tons per year. These rules ensure that all potential leaks at oil and natural gas facilities are controlled (reduced by 95% or greater) or are monitored and prevented through best management practices. Documentation and reporting was established so CDPHE could ensure compliance and allow for transparency to the public regarding the safety of air quality around oil and natural gas facilities.
[1] https://www.colorado.gov/pacific/cdphe/summary-oil-and-gas-emissions-requirements
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CDPHE AQCC
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2015 - Enforcement and Penalty Rulemaking
On January 5, 2015, the COGCC approved rule changes that increased the penalties for operators in violation of commission regulations.[1] This rulemaking was spurred by a perception that the COGCC’s penalties were inadequate. In response to this concern, Executive Order D 2013-004 was issued in May 2013, directing the COGCC to review its enforcement program, penalty structure, and imposition of fines. The Commission provided its Enforcement and Penalty Policy Review to the Governor’s Office in December 2013. On June 6, 2014, House Bill 14-1356 amended the Act to strengthen the penalty authority of the Commission.
The revisions to COGCC’s enforcement and penalty rules adopted through this rulemaking served to implement HB 1356. Per the COGCC, the rule changes were intended to deter violations and to ensure operators prompt compliance with COGCC regulations. The increased penalties went in to effect on March 2, 2015. There were 20 non-enforcement rules amended as part of this rulemaking, which went in to effect February 14, 2015.
Under the new rules, the maximum daily penalty was increased from $1,000 to $15,000 for each violation, eliminating the $10,000 overall cap for each violation. The rules included the creation of a penalty matrix which classifies each Notice of Alleged Violation (NOAV) as a major, moderate, or minor degree of impact, and classification of rules as Class 1, 2, or 3 based on the potential for harm under the violation. A Class 1 violation creates no risk or harm, a Class 2 violation creates possibility of harm, and a Class 3 violation creates probability of harm. The penalty assessed is dependent upon where the NOAV falls within this matrix. Operators are required to respond to NOAV’s in a detailed and thorough manner and all documentation is available on the COGCC website. This rule also included new presumptions for determining the duration of a violation based on when they were, or should have been discovered, and when corrective action has commenced, and an additional matrix to determine penalties for long duration violations.
Another key component of this rule was the establishment of a new COGCC webpage for complaints, which allows members of the public to file and track complaints through an online database.
[1] http://cogcc.state.co.us/documents/reg/Rules/LATEST/500Series.pdf
The revisions to COGCC’s enforcement and penalty rules adopted through this rulemaking served to implement HB 1356. Per the COGCC, the rule changes were intended to deter violations and to ensure operators prompt compliance with COGCC regulations. The increased penalties went in to effect on March 2, 2015. There were 20 non-enforcement rules amended as part of this rulemaking, which went in to effect February 14, 2015.
Under the new rules, the maximum daily penalty was increased from $1,000 to $15,000 for each violation, eliminating the $10,000 overall cap for each violation. The rules included the creation of a penalty matrix which classifies each Notice of Alleged Violation (NOAV) as a major, moderate, or minor degree of impact, and classification of rules as Class 1, 2, or 3 based on the potential for harm under the violation. A Class 1 violation creates no risk or harm, a Class 2 violation creates possibility of harm, and a Class 3 violation creates probability of harm. The penalty assessed is dependent upon where the NOAV falls within this matrix. Operators are required to respond to NOAV’s in a detailed and thorough manner and all documentation is available on the COGCC website. This rule also included new presumptions for determining the duration of a violation based on when they were, or should have been discovered, and when corrective action has commenced, and an additional matrix to determine penalties for long duration violations.
Another key component of this rule was the establishment of a new COGCC webpage for complaints, which allows members of the public to file and track complaints through an online database.
[1] http://cogcc.state.co.us/documents/reg/Rules/LATEST/500Series.pdf
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2015 - Flood Lessons Learned Rulemaking
On September 9, 2013, a slow moving cold front stalled over Colorado, dropping record amounts of rainfall across 17 counties, and triggering a 100-year flood event.
The oil and natural gas industry was prepared and able to respond to the flood immediately; opening incident command centers, shutting in wells, enacting emergency action plans, and activating around the clock monitoring and response at their facilities- all before the floodwaters started rising. The majority of operators in the DJ Basin had little to no impact to their well sites with the operations impacted ranging from standing water to fast moving flood waters. Of the 20,000 wells in the DJ Basin, 2,658 were shut-in at the peak of the flood, with only 13 notable releases of oil and 17 incidents of produced water releases.
In March 2014, the COGCC published a report “Lessons Learned in the Front Range Flood of September 2013”. This report contained several recommendations for oil and natural gas wells and production facilities located in flood impact zones, including:
Effective June 1, 2015 for all new wells and equipment, and April 1, 2016 for retrofitting of existing equipment, all new wells were required to be equipped with remote shut-in capabilities prior to commencing production and have enhanced secondary containment areas around tanks located in flood plains or sensitive areas. Secondary containment must have a liner that is mechanically connected to a steel ring or another engineered technology that provides equivalent protection.
Finally, effective April 1, 2016, all operators are required to maintain a current inventory of all existing wells, tanks, and separation equipment in a defined floodplain. This inventory must be filed will the Director of the COGCC and include information on how these locations can be remotely shut-in.
[1] http://cogcc.state.co.us/documents/reg/Rules/2015/FloodPlain/FinalRule.pdf
The oil and natural gas industry was prepared and able to respond to the flood immediately; opening incident command centers, shutting in wells, enacting emergency action plans, and activating around the clock monitoring and response at their facilities- all before the floodwaters started rising. The majority of operators in the DJ Basin had little to no impact to their well sites with the operations impacted ranging from standing water to fast moving flood waters. Of the 20,000 wells in the DJ Basin, 2,658 were shut-in at the peak of the flood, with only 13 notable releases of oil and 17 incidents of produced water releases.
In March 2014, the COGCC published a report “Lessons Learned in the Front Range Flood of September 2013”. This report contained several recommendations for oil and natural gas wells and production facilities located in flood impact zones, including:
- improved secondary containment and tank construction requirements; and
- locating structural fencing and barriers upstream of production facilities to deflect debris; adding automated controls to monitor and shut-in wells remotely; and
- alignment of production facilities outside of drainage or flow paths.
Effective June 1, 2015 for all new wells and equipment, and April 1, 2016 for retrofitting of existing equipment, all new wells were required to be equipped with remote shut-in capabilities prior to commencing production and have enhanced secondary containment areas around tanks located in flood plains or sensitive areas. Secondary containment must have a liner that is mechanically connected to a steel ring or another engineered technology that provides equivalent protection.
Finally, effective April 1, 2016, all operators are required to maintain a current inventory of all existing wells, tanks, and separation equipment in a defined floodplain. This inventory must be filed will the Director of the COGCC and include information on how these locations can be remotely shut-in.
[1] http://cogcc.state.co.us/documents/reg/Rules/2015/FloodPlain/FinalRule.pdf
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2015 - Complainant Rulemaking
On July 20, 2015, the COGCC approved rule changes implementing a streamlined process for the public to submit complaints. The new online portal makes the agency’s methods for receiving, processing, addressing, closing and communicating complaints more effective and transparent. It includes guidance for making a complaint, what a complainant can expect and the rights of the complainant.
A key component of this rulemaking was the definition of a new term "Petition for Review" which gives the commission authority to remand a petition back to the director if they disagree with it. The Commission adopted a new process for review, initiated by a complainant filing a Petition for Review. Brief argument by the complainant, the director, the affected operator, and any intervenors will be allowed. The Commission will review the director’s decision pursuant to a “clearly erroneous” standard. It is the complainant’s burden to show the director’s decision was clearly erroneous.
Should the Commission find the director’s decision was clearly erroneous, it may remand the matter to the director for further proceedings, set the matter for an OFV (Order Finding Violation) hearing in which the director would prosecute an alleged violation, issue an NOAV (Notice of Alleged Violation), or order other relief it deems just and reasonable. If the Commission finds the director’s decision was not clearly erroneous, it will deny the Petition for Review.
The streamlining of the complainant process has positive impacts on all parties as it brings the complainant’s objections to the Commission sooner than under the previous process. This increase in efficiency benefits all affected classes of persons as it generally reduces the cost of resolving a complainant’s objections.
A key component of this rulemaking was the definition of a new term "Petition for Review" which gives the commission authority to remand a petition back to the director if they disagree with it. The Commission adopted a new process for review, initiated by a complainant filing a Petition for Review. Brief argument by the complainant, the director, the affected operator, and any intervenors will be allowed. The Commission will review the director’s decision pursuant to a “clearly erroneous” standard. It is the complainant’s burden to show the director’s decision was clearly erroneous.
Should the Commission find the director’s decision was clearly erroneous, it may remand the matter to the director for further proceedings, set the matter for an OFV (Order Finding Violation) hearing in which the director would prosecute an alleged violation, issue an NOAV (Notice of Alleged Violation), or order other relief it deems just and reasonable. If the Commission finds the director’s decision was not clearly erroneous, it will deny the Petition for Review.
The streamlining of the complainant process has positive impacts on all parties as it brings the complainant’s objections to the Commission sooner than under the previous process. This increase in efficiency benefits all affected classes of persons as it generally reduces the cost of resolving a complainant’s objections.
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2016 - Governor's Oil and Gas Task Force Rulemaking
On August 4th, 2014, Governor John Hickenlooper announced the formation of an oil and gas development task force, which was established through Executive Order B2014-005 in September 2014.[1]
The Task Force was comprised of 21 members representing local government, civic organizations, environmental interests, agriculture, and affected industries. It convened monthly from September 2014 through February 2015.[2]
At the final meeting, the Task Force put forth nine recommendations, seven of which were approved unanimously. Two of the unanimously approved recommendations, numbers 17 and 20, required a formal rulemaking of the Colorado Oil and Gas Conservation Commission (COGCC) to implement. On November 16, 2015, the COGCC initiated a formal rulemaking hearing process to hear public comment, solicit feedback from the oil and gas industry and other stakeholders. The COGCC held two additional hearings before approving the final rules on January 25, 2016.
Task Force Recommendation 17 was to “Facilitate Collaboration of Local Governments. Colorado Oil and Gas Conservation Commission and Operators Relative to Oil and Gas Locations and Urban Planning.” Recommendation 17 called for COGCC to define and adopt a process for improved local government involvement during the COGCC permitting process for Applications to Drill (APD) concerning the location of large scale oil and gas facilities in Urban Mitigation Areas (UMA). The intent of this recommendation was to give local governments tools to represent their constituents to a greater degree through added engagement with operators and, as needed, stakeholder groups.
Task Force Recommendation 20 was a “Recommendation to Include Future Oil and Gas Drilling and Production Facilities in Existing Local Comprehensive Planning Processes.” Recommendation 20 proposed that all operators would be required to register in the municipalities in which they have operations and provide information on their planned development and operations within those municipalities. Operators would be required to provide a good faith estimate of the number of wells that they intend to drill in the next five years, a map showing the location of existing well sites and related production facilities, sites undergoing permitting, and sites identified for development. This information would allow the planning department to develop comprehensive maps to identify areas of potential conflict, areas where minor issues are anticipated, and areas where there are no compatibility issues. This proposal was intended to be a framework to facilitate improved coordination of drilling plans in to municipal planning.
The final rules implementing Recommendation 17 include the following:
The final rules implementing Recommendation 20 include the following:
Of the conforming rule changes adopted, two were of specific importance to operators:
[1] https://www.colorado.gov/pacific/governor/atom/18521
[2] https://cogcc.state.co.us/reg.html#/rules
[3] http://cogcc.state.co.us/documents/reg/Rules/LATEST/100Series.pdf
[4] http://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf
[5] http://cogcc.state.co.us/documents/reg/Rules/LATEST/600Series.pdf
[6] http://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf
The Task Force was comprised of 21 members representing local government, civic organizations, environmental interests, agriculture, and affected industries. It convened monthly from September 2014 through February 2015.[2]
At the final meeting, the Task Force put forth nine recommendations, seven of which were approved unanimously. Two of the unanimously approved recommendations, numbers 17 and 20, required a formal rulemaking of the Colorado Oil and Gas Conservation Commission (COGCC) to implement. On November 16, 2015, the COGCC initiated a formal rulemaking hearing process to hear public comment, solicit feedback from the oil and gas industry and other stakeholders. The COGCC held two additional hearings before approving the final rules on January 25, 2016.
Task Force Recommendation 17 was to “Facilitate Collaboration of Local Governments. Colorado Oil and Gas Conservation Commission and Operators Relative to Oil and Gas Locations and Urban Planning.” Recommendation 17 called for COGCC to define and adopt a process for improved local government involvement during the COGCC permitting process for Applications to Drill (APD) concerning the location of large scale oil and gas facilities in Urban Mitigation Areas (UMA). The intent of this recommendation was to give local governments tools to represent their constituents to a greater degree through added engagement with operators and, as needed, stakeholder groups.
Task Force Recommendation 20 was a “Recommendation to Include Future Oil and Gas Drilling and Production Facilities in Existing Local Comprehensive Planning Processes.” Recommendation 20 proposed that all operators would be required to register in the municipalities in which they have operations and provide information on their planned development and operations within those municipalities. Operators would be required to provide a good faith estimate of the number of wells that they intend to drill in the next five years, a map showing the location of existing well sites and related production facilities, sites undergoing permitting, and sites identified for development. This information would allow the planning department to develop comprehensive maps to identify areas of potential conflict, areas where minor issues are anticipated, and areas where there are no compatibility issues. This proposal was intended to be a framework to facilitate improved coordination of drilling plans in to municipal planning.
The final rules implementing Recommendation 17 include the following:
- 100 Series Rules: Definition of a large-scale oil and gas facility in an urban mitigation area (Large UMA Facility) as any facility that proposes eight or more new wells or the cumulative new and existing on-site storage capacity for produced hydrocarbons exceeds 4,000 barrels.[3]
- Rule 305A: Any operator seeking to develop a Large UMA Facility is required to notify the local government with land use jurisdiction and offer to consult on siting and best management practices.[4] The operator is also required to provide notice to the surface owner on which the Large UMA Facility is proposed. This notice must be provided 90 days prior to submitting a Form 2A oil and gas location assessment to the COGCC.
- Consultation is not required if the local government with land use authority has opted out of the consultation process OR if the local government with land use authority and the operator seeking to develop have an existing agreement, like a MOU, in place to guide the siting of a proposed location.
- Rule 604.c.4: Operators are required to incorporate Required Best Management Practices in to their Form 2A Oil and Gas Location Assessment permit application.[5] The Director of the COGCC may also require site specific mitigation measures as conditions of approval on an operator’s permit, including conditions regarding noise, ground and surface water protection, visual impacts, and remote stimulation operations.
The final rules implementing Recommendation 20 include the following:
- Rule 302.c.: Effective May 1, 2016, operators will be required to register with each municipal jurisdiction and county where they have approved drilling units or pending Form 2 or Form 2A.14 Additionally, municipalities, not counties, may request that an operator provide a good faith estimate of the number of wells they plan to drill in the next five years, in that local jurisdiction.
Of the conforming rule changes adopted, two were of specific importance to operators:
- Rule 303.c.: If no decision has been issued on a Form 2A for a Large UMA facility, an operator must wait 90 days before requesting a hearing if there is agreement between the operator and local jurisdiction. In cases where agreement has not been reached between the local jurisdiction and the operator, operators must wait 120 days to request a hearing. [6]
- Rule 305.a.: Operators are required to provide no less than 45 days’ notice to proximate local governments that are within 1,000 feet of any proposed Large UMA facility. 16 The proximate local government will not have jurisdiction or authority to participate in the consultation process, however, they are permitted to file comments with the COGCC.
[1] https://www.colorado.gov/pacific/governor/atom/18521
[2] https://cogcc.state.co.us/reg.html#/rules
[3] http://cogcc.state.co.us/documents/reg/Rules/LATEST/100Series.pdf
[4] http://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf
[5] http://cogcc.state.co.us/documents/reg/Rules/LATEST/600Series.pdf
[6] http://cogcc.state.co.us/documents/reg/Rules/LATEST/300Series.pdf
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2016 State Implementation Plan (SIP)
Parts of Colorado have ongoing difficulties meeting EPA’s 2008 Ozone Standard of 75ppb. In May 2016, the EPA reclassified the Denver Metro/North Front Range area as in Moderate non-attainment with the 2008 Ozone Standard. Later that year, the commission adopted a revised State Implementation Plan (SIP) to further reduce ozone levels for the Denver Metropolitan and North Front Range nonattainment area.
The plan includes detailed technical analyses regarding the formation of ozone, future trends in ozone levels, strategies to reduce ozone, and other elements. It includes measures deemed necessary to comply with the standard by the 2018 deadline.[1]
The 2008 standard (75 ppb) was still in place through July 2018, giving Colorado a chance to comply. If the Denver-metro and North Front Range nonattainment area misses that deadline it could be bumped-up again, to a “serious” classification, as early as 2019.
In many ways, however, this issue is still ongoing. In 2015, the EPA ratcheted up the ozone standard again (now set to 70 ppb), which sets the stage for a new round of SIP revisions to adopt measures needed to meet the new standard.
[1] https://www.colorado.gov/pacific/cdphe/aqcc-2016-2017-report-public-major-initiative
The plan includes detailed technical analyses regarding the formation of ozone, future trends in ozone levels, strategies to reduce ozone, and other elements. It includes measures deemed necessary to comply with the standard by the 2018 deadline.[1]
The 2008 standard (75 ppb) was still in place through July 2018, giving Colorado a chance to comply. If the Denver-metro and North Front Range nonattainment area misses that deadline it could be bumped-up again, to a “serious” classification, as early as 2019.
In many ways, however, this issue is still ongoing. In 2015, the EPA ratcheted up the ozone standard again (now set to 70 ppb), which sets the stage for a new round of SIP revisions to adopt measures needed to meet the new standard.
[1] https://www.colorado.gov/pacific/cdphe/aqcc-2016-2017-report-public-major-initiative
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2016 to 2017 - AQCC CTG Rulemaking and Revisions to Reg 7
To further reduce ground-level ozone, improve air quality, and comply with federal requirements, the division, the commission and the Regional Air Quality Council have worked with external stakeholders, including COGA, to reduce emissions from oil and natural gas sources.
On October 27, 2016, EPA finalized the Control Technique Guidelines for the Oil and Natural Gas Industry (Oil and Gas CTG). The Commission determined that some sources covered by the Oil and Gas CTG were not addressed in existing regulations. The new rules included the following[1]:
[1] https://environmentalrecords.colorado.gov/HPRMWebDrawer/RecordView/111365
On October 27, 2016, EPA finalized the Control Technique Guidelines for the Oil and Natural Gas Industry (Oil and Gas CTG). The Commission determined that some sources covered by the Oil and Gas CTG were not addressed in existing regulations. The new rules included the following[1]:
- Requirements for monitoring pneumatic pumps
- Enhanced equipment leak monitoring at natural gas processing plants
- Provisions for compressors and leak detection and repair (“LDAR”) for components at well production facilities and natural gas compressor stations.
- Enhanced LDAR Requirements, recordkeeping, and reporting
- Continuous bleed, natural gas driven, pneumatic controllers for gas processing plants must be no-bleed (e.g. cannot actuate intermittently (vent), or at all).
[1] https://environmentalrecords.colorado.gov/HPRMWebDrawer/RecordView/111365
AQCC
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Reg 7
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2018 - Flowline Rulemaking
As part of the state’s response to the Firestone tragedy, on February 13, 2018, the COGCC unanimously approved dozens of new rules pertaining to flowlines and other types of piping systems, with other regulations increasing transparency in safety and gas leak reporting.
State regulations require operators to lock and mark any flowlines not in use or abandoned. All lines must continue to undergo integrity testing under the same standards as active lines until abandonment. Operators are also now required to become Tier 1 participants in the 811 call-before-you-dig system, which establishes a centralized home for all data on flowline locations.
These additional requirements give local communities, builders, and property owners the information they need to feel confident in the location and integrity of underground flowlines. The COGCC also set strict guidelines for flowline installation, design, registration, and management.
The 20-plus pages of new regulations detail some of the following requirements[1]:
[1] https://cogcc.state.co.us/documents/reg/Rules/FlowlineRulemaking/Flowline_Adopted%20Rules%202_13_18.pd
State regulations require operators to lock and mark any flowlines not in use or abandoned. All lines must continue to undergo integrity testing under the same standards as active lines until abandonment. Operators are also now required to become Tier 1 participants in the 811 call-before-you-dig system, which establishes a centralized home for all data on flowline locations.
These additional requirements give local communities, builders, and property owners the information they need to feel confident in the location and integrity of underground flowlines. The COGCC also set strict guidelines for flowline installation, design, registration, and management.
The 20-plus pages of new regulations detail some of the following requirements[1]:
- Operators must register off-location flowlines within 30 days of being placed into service. Flowlines built prior to May 1, 2018, must be registered by Oct. 31, 2019.
- Within 30 days of installation or discovery of a domestic tap connected to the operator’s flowline, the operator must register it with the COGCC.
- At least 10 days before beginning construction of a crude oil transfer line or produced water transfer system, the operator must register it with the COGCC.
- Upon request form a local government, the commission will provide location data of all flowlines, for the sole purpose of assisting local governments with emergency management and planning. This information will be kept confidential and will not be subject to the Colorado Open Records Act.
- A crude transfer line built after May 1, 2018 must be inspected by a third-party inspector before being placed into service.
- Operators must maintain flow lines; fix them when leaks are discovered, and all that are not actively in use must have isolation valves locked and tagged out.
- All lines must undergo integrity testing before being placed into service; new lines must adhere to steel weld industry standards.
- Every operator must become a Tier One member of the Utility Notification Center of Colorado and participate in Colorado’s One Call notification system.
- Operators must identify all lines that are not in service for more than a year.
- Perform annual maintenance of isolation valves.
- Isolation valves must be installed on all flowlines or crude transfer lines after May 1, 2018, at each point of transfer along the line: the suction end of a pump station, where they meet a breakout tank; at each point where such a line crosses a public water supply or reservoir storing water for human consumption.
- All existing flowlines and crude oil transfer lines must be retrofitted with isolation valves at various locations along the line, identified above. On-location manifold, peripheral and process piping flowlines are exempt from this rule.
- Annual pressure testing of lines, or smart pigging every three years.
- Remove all abandoned lines and risers associated with the lines.
[1] https://cogcc.state.co.us/documents/reg/Rules/FlowlineRulemaking/Flowline_Adopted%20Rules%202_13_18.pd
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2018 - Enforce Requirements 811 Locate Underground Facilities
The bill creates the underground damage prevention safety commission (commission) as an independent agency within the department of labor and employment. The commission has rule-making and enforcement authority regarding specified portions of the excavation damage prevention law and is required to enter into a memorandum of understanding with the notification association to facilitate implementation and administration of the law. The notification association is required to provide administrative support to the commission in performing its duties. [1]
A review committee of the commission initially determines whether a violation of the law has occurred and, if appropriate, recommends remedial action, potentially including a fine. Fines range from $250 for a single minor violation within the previous 12 months to $75,000 for a fourth major violation within the previous 12 months. The full commission is bound by the review committee's determination of facts but determines the final agency action regarding alleged violations. Fines are credited to the damage prevention fund, which the commission will use to develop educational programming, including by making grants, that is designed to improve worker and public safety relating to excavation and underground facilities.[2]
[1] https://leg.colorado.gov/bills/sb18-167
[2] https://leg.colorado.gov/bills/sb18-167
A review committee of the commission initially determines whether a violation of the law has occurred and, if appropriate, recommends remedial action, potentially including a fine. Fines range from $250 for a single minor violation within the previous 12 months to $75,000 for a fourth major violation within the previous 12 months. The full commission is bound by the review committee's determination of facts but determines the final agency action regarding alleged violations. Fines are credited to the damage prevention fund, which the commission will use to develop educational programming, including by making grants, that is designed to improve worker and public safety relating to excavation and underground facilities.[2]
[1] https://leg.colorado.gov/bills/sb18-167
[2] https://leg.colorado.gov/bills/sb18-167
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2018 - Pooling & Hearing Process Clean-Up Rulemaking
The Colorado Oil and Gas Conservation Commission will implement SB18-230 changes to the pooling statute and consider additions and amendments to the 500 Series, Rules of Practice and Procedure, and to any other rule related to the process used to establish or manage a hearing matter under 2 C.C.R. 404-1. This “Hearing Process Rulemaking” will improve the State’s pooling process and clarify COGCC’s rules in order to streamline the process used by operators to initiate a hearing matter for consideration by the Commission, and the process used by COGCC staff to manage hearing matters.[1]
[1] https://cogcc.state.co.us/documents/reg/Rules/HearingProcessRulemaking/Pooling%20and%20Hearing%20Process%20Clean-Up%20Rulemaking%20Timeline.pd
[1] https://cogcc.state.co.us/documents/reg/Rules/HearingProcessRulemaking/Pooling%20and%20Hearing%20Process%20Clean-Up%20Rulemaking%20Timeline.pd
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2018 - Greater School Setback Rulemaking
In response to community feedback, the Colorado Oil and Gas Association (COGA) worked in conjunction with key stakeholders, including environmental groups and school districts, to reach an agreement regarding the December 2018 Colorado Oil and Gas Conservation Commission (COGCC) rulemaking on changes to the state’s school setback distances.
The submission of a Commission petition to conduct a rulemaking to require new oil and gas wells and production facilities be sited no closer than 1,000 feet from the perimeter of a school or child care center property line, as opposed to a building as currently required. At the Commission’s July 30, 2018 hearing, it considered the petition and directed Commission staff to proceed with a rulemaking on the issue of school setbacks.
While the current setback distance of 1,000 feet does not change, the rulemaking redefines what a school facility is, broadening the boundary, along with a few other clarifying changes:
The submission of a Commission petition to conduct a rulemaking to require new oil and gas wells and production facilities be sited no closer than 1,000 feet from the perimeter of a school or child care center property line, as opposed to a building as currently required. At the Commission’s July 30, 2018 hearing, it considered the petition and directed Commission staff to proceed with a rulemaking on the issue of school setbacks.
While the current setback distance of 1,000 feet does not change, the rulemaking redefines what a school facility is, broadening the boundary, along with a few other clarifying changes:
- SCHOOL FACILITY means any discrete facility or area, whether indoor or outdoor, associated with a school, that students use commonly as part of their curriculum or extracurricular activities. A school facility is either adjacent to or owned by the school or school governing body, and the school or school governing body has the legal right to use the school facility at its discretion. The definition includes Future School Facility.
- FUTURE SCHOOL FACILITY means a school facility that is not yet built, but that the school or school governing body plans to build and use for students and staff within three years of the date the school or school governing body receives a pre-application notice pursuant to Rule 305.a.(4). In order to be considered a future school facility, the following requirements must be satisfied:
- For public, non-charter schools, the school governing body must affirm the nature, timing, and location of the future school facility in writing;
- For charter schools, the school must have been approved by the appropriate school district or the State Charter School Institute, § 22-30.5-505, C.R.S., at the time it receives a preapplication notice pursuant to Rule 305.a.(4), and the school governing body must affirm the nature, timing, and location of the future school facility in writing;
- For private schools, the school governing body must be registered with the Office of the Colorado Secretary of State at the time it receives a pre-application notice pursuant to Rule 305.a.(4), and must provide documentation proving its registration with the Office of the Colorado Secretary of State, its tax exempt status, and its submitted plans to the relevant local government building and planning office.
- CHILD CARE CENTERS as defined in § 26-6-102(5), C.R.S. that is in operation at the time of the pre-application notice pursuant to Rule 305.a(4). A child care center will include any associated outdoor play area adjacent to or directly accessible from the center and is fenced or has natural barriers, such as hedges or stationary walls, at least four (4) feet high demarcating its boundary
- WAIVER REQUIREMENT describes how the relevant governing body agrees in writing to the location of the proposed well or production facility within the setback, in which circumstances the Director may approve the Form 2, Application for Permit to Drill, or Form 2A, Oil and Gas Location Assessment.
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