Oil and Gas Q&A

On September 23, 2026, Erie Together hosted a panel at the Erie Community Library to help residents to deepen their understanding of how oil & gas affects them. Panelists included Ashley Jones, an Oil and Gas liaison from the Colorado Department of Public Health and the Environment, Air Quality Control Division; Ben Kellond, Town of Erie Environmental Analyst, Dan Zimmerle, Director of CSU Methane Emissions Technology Evaluation Center, and Dr. Joseph Ryan, CU Professor of Civil, Environmental and Architectural Engineering.

The Town of Erie and its residents have been heavily impacted by oil and gas development, resulting in ground and air pollution. The speakers address various governmental roles to oversee oil and gas, as well as academic studies of air and water pollution resulting from the industry.

The You Tube video captures the speakers, their slides, films and questions asked of them from the audience via the moderators, Steve Drew and Carol Campbell of Erie Together.

Questions that were not answered during the panel:

Q: How many projects are not approved because of CDPHE input? Did CDPHE raise concerns on Draco and the Aurora Reservoir to the ECMC?

Ashley Jones, CDPHE - 9/30/2026

During the consultation process, CDPHE asks operators to adopt best management practices (BMPs) beyond what is required by regulation in order to go above and beyond to protect public health. Since these BMPs are voluntary, the refusal to adopt them by the operator is not grounds for the denial of a drilling application before the ECMC Commission. However, we warn operators that the failure to adopt a feasible BMP will be scrutinized by the commissioners during their hearing and that they will need to provide a rational justification for why a particular BMP was not adopted. Operators have realized that these are uncomfortable questions from the commissioners and therefore agree to feasible BMPs.

The CDPHE consultation for Draco can be found here. CDPHE issued an update with a correction to the original consultation a few weeks later and that correction can be found here.

Q: Are heat emissions of concern from oil and gas?

Daniel Zimmerle - 9/28/26
Director, Methane Emissions Program
Director, Remote and Distributed Energy Center (RADEC)
Energy Institute | Colorado State University

There are several ways to look at this.  Let’s assume the question is w.r.t. heat generated by combustion on O&G sites.  First, the heat & CO2 emissions are similar to any other combustion source, including gasoline in your car or coal-fired electricity.  The global warming impact is dependent only on the mass of CO2 and methane emitted (plus smaller amounts of a few other gases).

Second, combustion processes also produce other air pollutants, including HAPs (hazardous air pollutants).  These have a local effect depending upon wind transport and dispersion near the site.  As a result, HAPS are regulated by federal, state, and, less frequently, local authorities.

Ashley Jones, CDPHE - 9/30/2026

The Air Pollution Control Division (APCD) regulates the emissions of pollution from oil and gas sources. 'Heat' is not a regulated pollutant so the short answer is that APCD does not have the authority to regulate sources of heat. That said, combustion sources are regulated by APCD because of the emission of regulated pollutants like NOx and VOC (which are ozone precursors), other criteria pollutants (like particulate matter (PM) and carbon monoxide (CO)) as well as hazardous air pollutants (HAPs) like Dan mentioned. 

Q: Who is in charge of monitoring emissions?

Daniel Zimmerle - 9/28/26
Director, Methane Emissions Program
Director, Remote and Distributed Energy Center (RADEC)
Energy Institute | Colorado State University

In practice for air emissions, multiple parties have different ability to observe emissions and the processes that create them, so multiple parties need to be ‘in charge,’ meaning they are responsible for monitoring.   Generally, companies are better positioned to understand processes on their facilities and therefore monitor and maintain them.  Air regulators have tools to observe nearby and at a distance, and can spot problems due to non-compliance, unknown effects, or random failures.  It is unlikely that any one party has optimal access to the information required to monitor emissions. 

The situation with O&G sites is a different flavor of the vehicle emissions testing you all experience: You’re responsible for your vehicle’s emissions, and the state can force you to check your emissions (my diesel pickup is tested every year) or spot your emissions when you drive past a roadside monitor.

Ashley Jones, CDPHE - 9/30/2026

I assume this question is referring to the pre-production and early production air quality monitoring that I spoke about during the panel. This monitoring is required by Regulation 7 for all drilling projects in Colorado, not just along the front range. Every operator is responsible for conducting this monitoring at their site. The operator (or their designee) must submit a monitoring plan to the air division for review and approval prior to the commencement of drilling. These plans are carefully reviewed to ensure that public health is prioritized and protected to the maximum extent possible and that the monitoring is conducted in such a way that the data collected by the monitors is valid and representative of the air quality at the site. Upon the commencement of drilling, the operator must submit a report to the air division monthly that includes all of the data logged by the air monitors at the site. The air division closely analyzes this data to ensure that the monitoring is being conducted correctly. 

Q: What is being done to get into compliance with ozone on the front range?

Ashley Jones, CDPHE - 9/30/2026

Our staff work tirelessly to develop and implement new strategies for reducing ozone pollution across the state and in the areas of Colorado that do not meet federal health standards for ground-level ozone. However, we acknowledge there is always more to do.

Within the last few years, our division has developed and implemented several regulatory updates to reduce the emissions of volatile organic compounds and nitrogen oxides, which are types of air pollutants that contribute to ground-level ozone pollution. Some of our work to address ozone pollution includes: 

• The Nitrogen Oxides (NOx) Reduction Program for Upstream Oil and Gas Operators, which Colorado initiated in March 2023 at the direction of Gov. Polis. In December 2025, the committee completed its recommendations for future regulatory updates to address these ozone-forming emissions.

• The Pneumatic Controller and Pump Retrofit Program, which Colorado adopted in February 2025.

• Updates to the Vehicle Inspection and Maintenance Program, which Colorado adopted in January 2025.

• The Midstream Fuel Combustion Equipment Rule, which Colorado adopted in December 2024.

• The Greenhouse Gas Intensity Program for Upstream Oil and Gas Operators, which Colorado last updated in May 2024.

In November 2026, the Colorado Air Quality Control Commission will consider updating Colorado Air Quality Control Commission Regulation 29 to include commercial lawn and garden equipment in its summertime use restrictions.

We encourage Coloradans to share their feedback and participate in our rule proposal process. Our outreach web page has several opportunities for community members to get involved and stay updated on the division’s work.

Q: How much water is used per well development?  Does frack water go back into the water cycle?

Daniel Zimmerle - 9/28/26
Director, Methane Emissions Program
Director, Remote and Distributed Energy Center (RADEC)
Energy Institute | Colorado State University

On the order of ‘millions of gallons’ of water are used to frac a well.  It is highly variable depending upon the length of the horizontal section of the well and the requirements for the rock layer. https://www.usgs.gov/faqs/how-much-water-does-typical-hydraulically-fractured-well-require

A significant portion, but not all, of that water ‘flows back’ during early production of the well.  This water, plus water resident in the production strata, are the ‘produced water’ mentioned in O&G development.  Reuse and disposal of water production is complex and highly varied.

Q: What percentage of funding do you get from industry, government, and non oil and gas funding?

Daniel Zimmerle - 9/28/26
Director, Methane Emissions Program
Director, Remote and Distributed Energy Center (RADEC)
Energy Institute | Colorado State University

(DZ) My research group is funded by a combination of federal government, state government, industry, and environmental NGOs.  The fraction varies widely by year and the projects currently underway.  In general, we work with all parties and provide the same results to all parties.  We’re ‘equally loved and hated’ by all sides.

Q: Is there ever no risk from plugged and abandoned well?

Daniel Zimmerle - 9/28/26
Director, Methane Emissions Program
Director, Remote and Distributed Energy Center (RADEC)
Energy Institute | Colorado State University

Like many technical topics, there is never a scenario where there is no risk, although there are many in which the risk may be small relative to other topics.  In my group, we’ve looked at both recent and older P&A’d wells.  We did not find emissions from recently plugged wells.  That does not mean there are (a) no emissions – emissions may have been too small for us to detect, or (b) no chance of future emissions.  I know of no long-term monitoring data, although there is at least one eNGO that is looking at a study in that area.  Old plugging jobs were more varied, ranging from quite professional efforts to very poorly done efforts; these are more variable but none emitted as much as recently abandoned, orphan, wells. Getting a long-term picture, or checking a large number of wells is expensive and requires enforced land access and multi-million $ funding to complete. 

A more recently identified issue is that new frac’ing may cross-couple into existing wells, including lower bores of plugged conventional wells.  I’m not an expert on the details, but know that operators are taking more precautions to identify existing bores during drilling operations than was done previously.  The economic incentive is solid; cross coupling into an uncontrolled existing bore hole can ruin a well and trash an expensive drilling investment.