PARACHUTE – When it comes to oil and gas companies, Bob Arrington has seen them come and seen them go. Arrington has, in succession, wrangled with three different drillers all showing up at his Battlement Mesa doorstep.
First there was Antero Resources, which sold out to Ursa Resources, which then went bankrupt with its assets bought by Houston-based Terra Energy Partners.
Along the way there have been negotiations, a promised $1 million to the community, protests and lawsuits. “We had incidents right and left,” said 84-year-old Arrington, a retired mechanical engineer. “It has been frustrating.”
The ins and outs of drilling at Battlement Mesa, a Western Slope planned community of 4,500 along Colorado River, are a microcosm of the shifting patterns of ownership of oil and gas assets in the state.
In whose hands those wells and pipelines end up will determine if they are well run or turn into nuisances and environmental problems, and also whether they are properly plugged and abandoned when they no longer produce.
Since 2017, more than 42,000 oil and gas properties have changed hands, according to state data, including thousands of pits, with unlikely names such as Merlot and Oink Oink, pipelines, waste storage wells and gas compressors and plants.
For the most part the transfers have been driven by large-scale changes in corporate strategies, mergers and bankruptcy sales. This includes a major consolidation of Western Slope operations now controlled by Terra and two other private-equity backed companies.
A prime focus of state regulators, however, is the transfer of inactive and low-producing wells. Of the nearly 52,000 wells in Colorado 9,586 produced no oil or gas in 2020 and another 10,763 yielded less than the equivalent of 2 barrels of oil a day, or BOE – a level at which regulators and industry experts say a well becomes uneconomical to operate.
Another 5,581 produced less than 5 BOE a day, a level at which state regulators have identified as potentially needing further review and financial assurance.
It is the fate of these 25,930 wells, especially when they are transferred from company to company, that concerns the regulators, environmental organizations and community groups.
If they fall into the wrong hands – fly-by-night operators, under-capitalized companies – they risk ending up abandoned and orphaned, leaving the state on the hook for plugging and cleanup.
“The concern is marginal properties going to marginal operators,” said Andrew Forkes-Gudmundson, deputy director of the League of Oil and Gas Impacted Coloradans, or LOGIC, a community organizing group. “The risk is that with a marginal operator with a portfolio filled with low-producing marginal assets there is less cash to pay for plugging and abandonment.”
COGCC overhauls its financial assurance rules
The risk of a well being orphaned is “heightened” when operators transfer aging wells, according to the Interstate Oil and Gas Compact Commission. The commission, which reviews policy, does research and training for its 38 states, said there are more than 92,000 documented orphan wells in the U.S.
A review by The Colorado Sun of five years of transfers tallied changes in ownership of 14,387 producing wells, 2,429 shut-in wells and temporarily abandoned wells and about 500 sites approved for drilling but not yet drilled.
There were also about 1,877 abandoned locations and nearly 2,400 plugged and abandoned wells that changed hands.
A complete list of wells was difficult to assemble since nearly 18,000 of the transfers were listed as “active” locations, which can include multiple properties. A review of 2,500 of the active location transfers found they included 205 wells.
Buried in those transfers were 6,323 wells producing less than 2 BOE a day and another 2,900 producing less than 5 BOE a day.
There are also about 90 pending transfer requests involving about 4,800 wells, including at least 541 producing less than 2 BOE a day and 225 wells producing less than 5 BOE a day.
The Colorado Oil and Gas Conservation Commission is in the process of overhauling its rules to stiffen financial guarantees for well plugging and abandonment. The most recent draft of rules will be the subject of hearings beginning Thursday.
The proposed rules include increasing financial assurance — be it a bond, letter of credit, sinking fund or cash — in the transfer of low-producing wells and added review of these transfers by the commission.
“This draft kind of goes back to the idea that certain wells are appropriate for that scrutiny,” said Julie Murphy, the COGCC’s executive director.
“Things have gotten pretty quiet”
Still, not every transfer is a bad one as Arrington and Battlement Mesa have learned.
With its golf course and swimming pool Battlement Mesa, just outside of the town of Parachute, was marketed as an ideal retirement community and that is what lured Arrington and his wife, Ann, to the development from Glenwood Springs in 2008.
About a year later, Denver-based Antero Resources turned up with plans to drill 200 wells in Battlement Mesa, including one well pad on the golf course, in front of Arrington’s Cape Cod-style home.
Antero held more than 30 community meetings to discuss plans, cut the number of drilling pads to nine from 10 and promised to install air monitors. The company pledged to give $1 million to the Battlement Mesa community.
In July 2011, just as Antero’s operations were getting underway, Battlement Mesa residents filed a lawsuit to require the driller to establish a fund to compensate for any losses in property value and to pay for medical monitoring and cover any health-related impacts.
Then in November 2012 Antero, a publicly traded company, sold its Western Slope assets for $325 million to Ursa Resources, an operator backed by private equity.
“Antero had hardly started and they were gone,” Arrington said.
Ursa took up where Antero left off, even agreeing to make good on the million-dollar promise.
Still, there was a string of incidents, Arrington said. Fumes from tanks not properly closed caused odor problems, a chemical spill dribbled benzene into the Colorado River, a fire in a pit sent toxic fumes skyward.
It was, however, the COGCC’s approval of Ursa’s PAD A, a 24-well site, that sent Battlement Mesa residents back to court.
Pad A was wedged between a tall bluff and the river, within 500 feet of some homes and next to the development’s drinking water treatment plant. “That site made no sense,” Arrington said. “To make the site big enough they were going to have to cut into the bluff and then have to reenforce the bluff.”
A Battlement Mesa citizens group filed a new lawsuit in Denver District Court in February 2019 to block the oil and gas commission approval arguing it was “not sufficiently protective of public health.”
But before the slow-moving wheels of justice had much turned, Ursa filed for bankruptcy in September 2020, citing the pandemic weakened energy market (in the first half of 2020 spot market natural gas prices slide 26%, to $1.63 a million per British thermal units or BTUs) and increased state regulations as a result of new laws passed by the legislature.
In November 2020, the bankruptcy court approved the sale of Ursa’s assets – 41,000 acres of mineral rights and 579 operating wells – to Houston-based Terra Energy Partners LLC for $60 million. That was less than a fifth of what Ursa had paid Antero eight years earlier.
Terra, backed by the New York-based investment bank Warburg Pincus and Los Angeles-based Kayne Anderson Capital Advisors, has amassed nearly 6,300 wells on the Western Slope from four different operators.
Battlement Mesa ended up getting just half of its promised $1 million. Part of that money, Arrington said, went into the landscaped traffic islands in the community.
Arrington, who is a member of the Garfield County Energy Advisory Board, met a Terra representative at a board meeting. “He was nice enough,” Arrington said. “He said they weren’t interested in drilling in Battlement Mesa.”
That became official in January 2020 with the announcement that the company would abandon all pending drilling permits within Battlement Mesa.
Jeff Kirtland, Terra’s regulatory manager and the designated agent for the company’s Colorado operation TEP Rocky Mountain, did not respond to email and telephone requests for comment. The telephone number listed on Terra’s website rang without answer.
“Things have gotten pretty quiet,” Arrington said. “Terra is just operating the wells to produce. It’s gotten quiet all across the Piceance Basin.”
Western Slope operations have consolidated
That’s true across the Western Slope, as operations have largely been consolidated in three companies, backed by private equity money – TEP Rocky Mountain, Caerus Oil and Gas and Laramie Energy. Collectively they are operating about 12,000 wells.
“There is a concern when most of the holdings are in a few of companies,” said Leslie Robinson, chairwoman of the Grand Valley Citizens Alliance, a grassroots group that has butted heads with Ursa and other Western Slope drillers. “However, they’ve bent over backwards to be part of the community.”
Companies made gestures such as buying 4-H Club livestock and providing meals to the needy during the pandemic.
They have also been more responsive. “In some ways it is easier to deal with just three operators,” Robinson said.
Brad Handler, a researcher at the Colorado School of Mines’ Payne Institute for Public Policy, says that “in a way, private companies have often proven to be more stable operators, more consistent operators than public ones. … They don’t have to justify continuing to spend money to investors.”
On the western cusp of the Roan Plateau, the iconic mesa in the heart of the Piceance Basin, Laramie Energy, the oldest and smallest of the trio, operates its Cascade Creek field, more than 700 wells that are mostly transfer hand-me-downs.
Way back, the assets were owned by City Services Co., which had an eye toward shale mining. In 1982, Occidental Petroleum acquired City Services and in 2015 Laramie bought the Western Slope operations from Occidental, nearly 15,000 acres. It operates about 1,500 wells.
Cascade Creek is a land of narrow and steep valleys in Garfield County, filled with sage and oak brush, and high plateaus fringed with evergreens and snow. No suburbanites here, just herds of elk and eagles and hawks riding the winds above.
The bulk of the wells — some in the valley, but most up on the plateaus — were drilled between 2005 and 2012, though some date back to the late 1980s.
“These wells have about a 40-year life,” said Chris Clark, Laramie’s vice president for operations, as his Jeep bounced down a winding, snow-covered, dirt road. “They just keep chugging along, although we had to plug one of the old ones last year.”
Clark said that in a mature field like Cascade Creek you have to “pick off a well here and there” on a pad for plugging. The company plugs between 10 and 15 wells a year.
The Occidental purchase also came with pipelines and a gas compression plant, built during the boom times in the early 2000s. The plant was constructed to handle 200 million cubic feet a day of gas, but now is only moving 15% to 20% of its capacity.
Back at the turn of this century with spot prices of natural gas reaching $16 per million BTUs, dozens of drillers scrambled over the Piceance Basin with more than 100 drill rigs punching holes into the hills.
There were traffic jams on Interstate 70, man-camps springing up to house roughnecks and police said they saw a rise in crime and drug use.
“It was really kind of a gold rush,” Caerus Oil and Gas CEO David Keyte said. “It is a different world now.” There are just two drill rigs running. Laramie may add a third in the spring.
Asset retirement plans are not guaranteed
In 2009, the year Caerus was formed with venture capital including backing from Philip Anschutz’s investment company and Los Angeles-based Oak Tree Capital Management, the bottom fell out of the natural gas market and prices plunged.
Caerus was the Greek god of opportunity and with advantageous asset prices Caerus the limited liability company moved in. “We started to identify this as a great gas basin that fell out of favor,” Keyte said.
The company has put together 70,000 acres of land plus leases and 4,200 wells, across Garfield, Mesa and Rio Blanco counties, through five major acquisitions, according to state data. This includes all of the holdings of Calgary-based Encana, which changed its corporate name to Ovintiv as part of a company reorganization, and ExxonMobil.
The $735 million purchase of Encana’s assets alone involved nearly 4,600 properties, including more than 400 wells producing less than 2 BOE a day, according to state data.
That is something that a buyer has to evaluate going into a purchase, Keyte said. “You put money aside upfront.” And every year the situation is reassessed under the company’s asset retirement obligation, or ARO, program.
“Caerus evaluates all of its wells annually to identify inactive wells suitable for inclusion in the ARO program,” Keyte said. The company plugged 26 wells in 2021 and plans to cap another 40 this year.
Such programs, however, aren’t guaranteed and the low-level of bonding the state now requires — $60,000 for four to 100 wells and $100,000 for 100 wells or more plus a $25,000 surface clean-up bond — make it easier to avoid committing resources to plugging and abandoning wells, critics say.
“We are pro financial assurance rules,” Keyte said. “To the extent that operators don’t execute on their liabilities there has to be a way to fix that.”
“You don’t know who is going to be a bad actor”
The revision of the COGCC financial assurance rules was mandated by Senate Bill 181, the 2019 law that changed the commission’s mission from promoting oil and gas development to protecting public health, safety and welfare, and the environment.
The law directed the commission to consider increasing financial guarantees for inactive wells and for wells transferred to new owners. An inactive well, by COGCC definition, is one that hasn’t produced any oil or gas in 12 months.
Some of these wells are shut in, which means the valves have been turned off for maintenance, safety reasons or because of low commodity prices. Some are categorized as temporarily abandoned, where equipment has been removed and a temporary plug put in place.
There are also thousands of wells listed as “producing” that yielded little or no oil and gas in 2020.
A low-producing well, under the COGCC definition, is one yield less than 2 barrels of oil or 10 MCF (thousand cubic feet) of gas a day.
Under the proposed rules, transfer forms would have to include the number of low-producing, inactive and out-of-service wells. An out-of-service well is one designated for plugging.
For those wells designated “out of service,” a date by which the well will be plugged would have to be included. There is no deadline currently for wells to be plugged. Transferring an out-of-service well would not change the plugging deadline.
Financial guarantees for plugging would have to be set aside for each low-producing well transferred – $10,000 for a well of less than 3,000 feet and $30,000 for a deeper well – or the plugging fund of an operator would have to be increased.
An operator has the option of demonstrating to the commission that its plugging costs are lower or that it can’t meet the requirements of creating a plugging fund.
Transfers could not go through without appropriate financial assurance. In cases where an unauthorized transfer took place the COGCC could order the wells shutdown.
The rules would also increase the amount of bonding or financial guarantees a company would have to post for all its wells.
An operator with less than 30% of its wells inactive would still be eligible for blanket bonds at an increased level – ranging for $15,000 to $1,500 a well, depending upon the number of wells an operator has. These operators would fall into Tier 1 of the proposed rules.
A company with 10 wells now has to post a $30,000 bond, under the rules that would rise to $150,000. A company with 4,000 wells now can post as little as $100,000, that would increase to $6 million.
Companies with more than 30% of their wells inactive would fall into Tier 2 and be required to create a sinking fund — a sort of savings account —that would cover the plugging of all their wells.
The draft regulations on transfers are a step forward, but still may not do away with the risks, LOGIC’s Forkes-Gudmundson said. “The proposed rules act as a backstop, a fail-safe, and that’s a good idea. I just worry that waiting until the well is already marginal is a point where it may be too late to start planning for asset retirement.”
There is also a hazard should the rules be too tough. “If the rules block transfers, some of those wells could be on a path to becoming orphan wells,” Forkes-Gudmundson said.
In the hands of an efficient, small operator, wells producing between 2 and 5 BOE a day can be profitable and not every small company is a risk, industry operators say.
“You don’t know who is going to be a bad actor,” Caerus’ Keyte said. “There are some of these family-owned companies that can run these wells more efficiently and can extend the life of the wells.”
For one operator, draft rules add a $17M “burden”
Out in Yuma County, along Colorado’s border with Kansas and Nebraska, corn is king. The county produces about a quarter of all the state’s corn and 50% more than the next biggest grower, neighboring Kit Carson County.
It wasn’t corn, however, that brought Own Resources, to the flat land and big sky of Yuma County. It was natural gas – old, shallow, low-producing, natural gas wells to be precise.
In 2018, Own Resources – the creation of two former McKinsey & Company oil industry consultants in partnership with Houston-based private equity firm Bayou City Energy – swooped in, amassing 1,900 old wells mostly in Yuma County.
In the rush for companies to drill shale wells, Own Resources says investors have ignored old but steady assets like the Yuma wells. “This creates a unique opportunity for experienced operators,” Own Resources said on its website.
Through the efficient management, a low-cost regime and operational improvements, Own Resources site says that it can make these low producing wells profitable. Ed Schneider, a company partner, declined to offer comment for this story.
Own Resources’ wells produce on average less than 2 BOE a day and so the question is how to assure that this army of wells – some 20 or 30 years old – will be plugged and abandoned by a company, whose Spring, Texas, address, according to COGCC records, is in a suburban development adjacent to a golf course?
Rather than doing the job, the proposed financial assurance rules could be a death knell for Own Resources.
“It will cost us about $22 million to remediate our field, for this we have plans, but the new draft rules place an additional burden of about $17 million to support orphan well funds and to pay surety providers,” Schneider said in testimony before the COGCC on Nov. 9. “The particular problem with payments to surety companies is that they pay to abandon zero wells.”
The Yuma County wells are shallow, around 2,500 feet, compared to the large, horizontal oil wells being drilled to depths of 10,000 feet.
While the COGCC estimates its average cost for plugging and abandoning cost for orphan wells at $92,700, in written commission testimony the company estimated its plugging costs in eastern Colorado ranged between $10,000 and $15,000 a well.
The solution, Schneider said, is to enable an operator to create “a sinking fund based on real costs and a reasonable time frame.”
The key question is the time frame. The current proposal gives Tier 2 operators 10 years to amass the funds to plug their wells. Own Resources estimates that its field has a 40-year life.
“For Own, it is akin to asking someone just out of college to fully fund their retirement plan by age 30, even though they have a 40-50 year working life,” the company’s managing partner Niels Phaf said in a written statement to the commission.
Some commissioners are reluctant to leave the funding until the end of a well’s life.
“You have a brand new well and it is producing a lot,” Commissioner Karin McGowan told Schneider. “It is easy to set money when you are making more. It is harder to set money aside when you are not making as much. … I am really struggling with how we figure this out.”
Still, an apparent moneymaker like Own Resources has resources. “Own Resources is a great example of a company where a sinking fund makes sense,” said Kate Merlin, an attorney representing the environmental group WildEarth Guardians in the financial assurance proceedings.
“Less than 1% of their wells are inactive,” Merlin said. “They are plugging as they go.”
In the last three years Own Resources has plugged 26 wells in Colorado, according to COGCC records.
“A sinking fund would work perfectly for a company like this,” Merlin said.
Transfers of low-producing assets raise concerns
There are, however, some companies smaller than Own Resources with nothing but low-producing wells that might not be able to bond or pay into a sinking fund. Some of these companies, such as 31 Operating and KP Kauffman Co., are already facing enforcement measures by the commission.
Another operator the commission moved against in October is San Antonio, Texas-based PCR Operating LLC. The commissioners voted to seize the company’s $535,000 in bonds, 151 gas wells and 12 waste injection wells in Morgan and Sedgewick counties.
The action came after PRC had been unresponsive for two years to agency notices of violations at its northeast Colorado wells.
The same day the commission voted to move on the PCR wells it also decided to take over 37 wells from three other defunct operators. On that one day the number of orphan wells in Colorado went to 427 from 239.
In 2018, well before the COGCC actions, PCR transferred 62 properties, including more than 20 wells, all either producing less than 2 BOE a day, shut in or temporarily abandoned – to WME Yates LLC.
Within three years the new operator had amassed 211 mostly low- and non-producing wells in Phillips and Sedgwick counties. Just one of its wells produced more than 5 BOE a day in 2020, according to state data, and more than 180 produced less than 2 BOE a day.
The company registered in Colorado in 2020 and has addresses in Beverly Hills and the Denver Tech Center and a residence in Denver. It shares one of those addresses and principals with Western Meadowlark Energy, a company that in turn is part of Rocky Mountain Resources, founded by Chad Brownstein, son of Denver lobbyist and attorney Norman Brownstein.
The University Park house that serves as the WME Yates business address, according to COGCC records, is owned by Jennifer Scott. Jen Scott is listed as WME Yates’ principal agent and as a Western Meadowlark agent.
When reached for comment by The Sun, a woman who identified herself as “Jen” said: “We are not actually interested in commenting … Hopefully you’re in the band camp of these small producers.”
For its wells WME Yates has been required to post a $100,000 bond for plugging and $25,000 for surface remediation. That is $474 a well for plugging – less than 5% of the cheapest estimate of plugging costs in the state.
So, companies like WME Yates raise concerns. “This transfer is definitely worrying – a non-responsive company transferring assets to a small company with low-producing assets,” LOGIC’s Forkes-Gudmundson “This doesn’t scream ‘this is a good thing for Colorado.’”
Colorado Sun staff writer Tamara Chuang contributed to this report.