New Colorado rules to insure there is enough cash to plug each oil and gas well in the state at the end of its life may not generate enough money to do the job, according to an analysis by Carbon Tracker.
The report by the nonprofit environmental think tank said that in the short-run the state may end up with less in financial guarantees than it had before the new rules were adopted nearly two years ago and about 39% of oil and gas companies still have not completed financial assurance plans.
The Colorado Energy and Carbon Management Commission, which adopted and administers the financial assurance rules, disputes those findings.
In April 2022, the state held 1,593 active bonds totaling about $243 million, the commission said in a statement to The Colorado Sun. The new rules were adopted in March 2022, and the ECMC now has 1,827 active bonds totaling $399 million.
The commission said it has approved financial assurance plans that will grow that amount to a projected balance of $641 million.
The financial assurance rules were required under Senate Bill 181, which reoriented oil and gas regulation in Colorado from promoting drilling to protecting public health, safety and welfare and the environment and wildlife.
The biggest share of those funds, however, will come from operators with many low-producing wells paying into their state plans over the next 10 to 20 years.
“This is a story of the haves and have-nots,” said Rob Schuwerk, executive director of Carbon Tracker’s North American office and a co-author of the report.
The “haves” are the large companies, who in many cases will see their bonding requirements go down, and the “have-nots” are smaller operators with marginal wells, who may face increased obligations.
“The money will mostly come from operators producing less than 2 boe/d (the equivalent of two barrels of oil a day) per well,” the report said. “Thus, the bulk of future bonding is exposed to low-producing operator default risk over a 10-year time horizon, replicating the problems SB19-181 was intended to solve.”
The ECMC said that it will retain the bonds posted by these smaller companies under the previous rules, which required bonding for plugging wells and surface cleanup, and the status of each operator will be reviewed annually.
The rules create five categories of financial assurance depending on the volume of oil and gas a company produces, with large companies able to cover their operations with blanket bonds.
The smaller, low-producing companies could have either 10 or 20 years to pay into a fund to meet plugging costs for each well or seek a customized plan.
“These strategies really aren’t going to be able to fix the problem because if you think about it, that means those entities will be contributing an additional 5% or 10% of their burden every year, as their wells produce less and less,” Schuwerk said.
The go-slow approach was adopted, Schuwerk said, because the commission was concerned that tougher regulations would trigger a rash of operator failures and a flood of new orphan wells.
Kate Merlin, an attorney with the environmental group WildEarth Guardians, said “the commission was trying to balance setting reasonable bond amounts that would protect the state and bonds too burdensome for operators.”
“I think they were a little too credulous about operators’ claims of too heavy a financial burden,” said Merlin, who reviewed the Carbon Tracker report. “It looks clear we aren’t going to end up with a substantial increase in bonds.”
Companies file plans, then go out of business
Companies must submit a financial assurance plan, a Form 3, and if approved, proof of bonding or fund contributions, a Form 3A.
The ECMC said that as of November 2023, approved plans covered 89% of the state’s 46,312 active wells and another 6% of the wells are in plans being reviewed.
However, only 8% of the plans have yet submitted plans and had approved their 3A proof of financial assurance, Carbon Tracker said.
The Carbon Tracker study noted that some of these companies aren’t making it through the financial assurance process.
WME Yates, which averaged a gas production equivalent of 35 barrels of oil a year from 2000 to 2023, submitted a Form 3, but before it was approved the company went out of business leaving 212 wells to the state.
Omimex Petroleum, with an average production equivalent of 75 barrels of oil over the past four years, had its Form 3 approved and then ceased operations leaving behind 339 wells.
The rules have created a Orphan Well Mitigation Enterprise fee — an annual per-well charge operators pay — and raised $18 million in its first two years to help address cases such as Yates and Omimex, the commission said.
Colorado also has received $25 million in federal funds to clean up orphan wells. In 2023, the ECMC spent $10.2 million and plugged and remediated 61 orphan wells.
Eighty-nine of the state’s 302 oil and gas companies have failed to submit a plan. They are all small, but collectively account for 2,393 wells, or about 5% of the 46,300 active wells, according to the ECMC.
The commission has already taken enforcement actions against 55 of those operators for failing to submit plans and is in the process of moving the wells of the remaining 28 operators into the state’s orphan well program.
Flexibility in regulations also created “loopholes”
The Carbon Tracker study identified what it calls “loopholes” in the regulations including: low bonds for big producers, avoiding bonding costs by putting wells on a six-year plugging list, the option for bespoke plans and the ability of low-producing operators to demonstrate that their plugging costs are lower than the state estimates.
The ECMC puts the average plugging and abandonment costs at $10,000 to $40,000 depending on the depth of a well plus $100,000 for site reclamation. Some operators put their “demonstrated” costs at $20,000 or less.
The long-term financing options for low producers were used by 137 operators and 37 of them proposed using demonstrated plugging costs. The ECMC denied the cost estimates in 30 plans.
The seven plans with demonstrated costs that were approved were in “operations with small, single-well, agriculturally approximate locations,” the commission said.
“The use of demonstrated costs is itself a major flaw in the rules, even if the ECMC has shown signs of addressing this through its review of operator demonstrated cost evidence,” the Carbon Tracker report said. “The fact that they have to do so is a problem.”
In all, through Feb. 6, the ECMC had rejected 43 plans out of 250 reviewed, the report said. When a plan is rejected, the operator is asked to submit a revised plan. There are now 44 plans pending.
The regulations created an out-of-service category in which wells would be plugged within the next six years. Wells in this category are removed from a company’s calculation of its financial assurance requirements.
Noble Energy, a subsidiary of Chevron Corp., placed 1,700 low-producing wells in the out-of-service category, and was able to reduce its financial assurance obligation to $6 million from $21 million, according to the report.
Noble Energy currently has $45 million in plugging bonds under the old financial requirement.
The ECMC said that the rule is working as it was designed because Noble has agreed to plug and remediate more than a thousand wells “instead of simply providing assurance for the wells and leaving them shut in as allowed under the previous rules.”
More than 4,000 wells have been moved into the out-of-service category; 3,500 of those wells are owned by Chevron, Occidental Petroleum and Civitas Resources, the three largest operators in the state.
Still, some smaller operators have also opted to use the category, sometimes to reduce their financial obligations.
Magpie Operating placed 59 of its 82 wells on the out-of-service list, which would require it to plug on average 10 wells a year, about double the number it has plugged annually in the past four years, according to the report. The company has 66 low-producing wells, according to ECMC data.
If an operator fails to meet the plugging deadline, they must provide financial assurance for each unplugged well. “Time will tell, but these wells may represent a ticking time bomb in the system,” the report said.
The option allowing companies to propose their own plans was labeled another loophole and was criticized during the rulemaking by Colorado environmental groups. “The inclusion of the custom plans really blew a lot of things out of the water,” Merlin said.
Own Resources, which operates 3,000 low-producing gas wells on the Eastern Plains, qualified for the option requiring $335 million in bonds, but under a custom plan approved by the ECMC it has to put up $8.3 million or $2,723 per well, according to the report.
“Own’s operation produces just gas, with essentially no liquid mineral,” the ECMC said in a statement to The Sun. “As a result, the remediation and reclamation of their locations are very low cost as there have been no impacts over time from liquid releases.”
“In addition, their locations are very small, single-well installations, which means the associated cost to reclaim is very small,” the commission said. Own also demonstrated that its wells still had long production lives.
There are 17 other operators with 2,500 wells also seeking tailor-made plans, many proposing very low bonding requirements, the report said.
The approximately 500 wells on the out-of-service list held by smaller companies, the 2,500 wells operators are seeking to place in low-cost, individual plans and the thousands of wells in the long-term options pose a risk, the Carbon Tracker said.
“In managing risk and liability the question isn’t what it is going to cost the operators, it is what is going to cost the state to plug and abandon those wells,” Schuwerk said.