In the last week of April, Primary Vision estimated only 10 hydraulic fracturing spreads were active in the Anadarko Basin, far short of the 167 in the Permian Basin or even the 33 in Appalachia. But like these areas, the Anadarko has a long history of oil and gas development, which means operators there benefit from fantastic well control and robust infrastructure. Add a friendly regulatory climate, and the Anadarko remains a place where operators of all sizes can generate attractive returns.

Indeed, companies active in the basin range from Marathon, Devon Energy and Continental Resources to smaller firms such as Lynx Resource Partners, Canvas Energy and Alvarado Minerals.

The basin’s appeal remains in all but the most severe price environments. Today, much of the drilling focuses on oil, but when gas prices recover, the Anadarko includes numerous places to find it. Many of the basin’s oil and gas plays do not lend themselves to dense development programs with eight-well pads, but they have enough breadth to be worth drilling.

Proven opportunities are expanding as operators seek to extend their inventories by developing new plays. In many cases, they are using data from legacy vertical wells and early horizontals to identify areas where today’s drilling and completion techniques may have huge payoffs.

Lynx Resource Partners LLC reports it is drilling wells targeting the Marchand sandstone, one of many benches within the Hoxbar trend that data from legacy wells suggests could be highly productive with today’s technology.

“There are many targets in the central part of the Anadarko Basin that have not been drilled fully with modern technology,” says Matthew J. Hatami, chief operating officer and one of the managing directors for Lynx Resource Partners LLC. He adds that such prospects can be identified in part because the Anadarko has some of the deepest wells in the United States. As operators drilled toward the Meramec and Woodford shales, they passed through other formations with appealing reserves, including the Red Fork, Skinner and Hoxbar.

“The Hoxbar alone has multiple sandstone and shale benches throughout,” Hatami enthuses. “At Lynx, we are focusing on the Marchand sandstone interval within the Hoxbar because there is enough data available from legacy vertical wells for us to calculate the original oil in place, compare that with historical production to estimate the existing wells’ drainage radii, and plan horizontals in areas we know contain unrecovered oil. This substantially reduces risk.”

As of early May, Lynx has drilled six horizontals into the Marchand. Most have vertical depths around 9,500-10,500 feet and lateral lengths between 5,000 and 10,000 feet, Hatami describes. He says the results have been strong.

“We are excited about our next well, the Master Chief 1H,” he comments. “The rock is thick. We have a lot of well control, and the Master Chief offsets one of the strongest Marchand horizontals to date, so the well should be low risk with high reward.”

Staying in Zone

Drilling the Hoxbar Marchand can be challenging, Hatami allows. “It’s a sandstone formation with rock abrasive enough that a bit is doing well if it manages to drill 1,500-2,000 feet before the rate of penetration drops and we need to trip out,” he reports. He notes that the company runs reamers above its bottom-hole assemblies to make trips as smooth and risk-free as possible.

Hatami and Al Warner, the company’s senior vice president of geology, both suggest that one of the biggest opportunities to bring the Hoxbar Marchand play to the next level is to do a better job of geosteering. “We can be in zone but not necessarily in the very best rock,” Warner says. “We are looking at several technologies to help us stay on target, such as switching from a conventional mud motor to a rotary steerable system.”

“During rotation, we can get good ROP with traditional bent assemblies,” Hatami reports. “However, when we go to slide, if we are seeing poor weight transfer or other issues that compromise tool face control, it is hard to stay in the optimal target interval. That is a situation where rotary steerable systems may make sense.”

The company also is experimenting with replacing its standard gamma ray tools with ones that can collect azimuthal gamma ray data, Hatami adds.

To reduce costs and optimize for the completion, Lynx’s well design includes two strings of casing rather than the three common in the play, Hatami notes. “We set conductor at 100 feet, then drill 1,500-2,000 feet and set 9 5⁄8-inch surface casing. For the rest of the well, we use an 8 3⁄4-inch bit and set 5 1⁄2-inch production casing,” Hatami details.

Lynx Resource Partners LLC uses cameras to support its completion, flowback and production operations. For example, during drilling, cameras on the shale shakers let the company monitor the cuttings without stepping away from its other telemetry.

“It is easier to run intermediate casing, but that is expensive enough that we have figured out how to optimize our mud system and BHA so the mud cake can act as a proxy casing,” he continues. “We drill to kickoff point with water-based mud, then trip out, change the BHA to the curve assembly, trip back in and then displace to oil-based mud and drill the rest of the lateral with it.”

Controlling mud weight is critical to building a cake that can hold the formation together, Hatami emphasizes. “We watch the shakers closely to see if there are any heaving shales coming through and make adjustments as needed,” he adds.

In its most recent wells, Lynx has placed cameras by the shakers. “With the cameras, we can continuously watch the cuttings while simultaneously monitoring all our other drilling telemetry,” Hatami describes. “That is good, because the faster we catch an issue, the lower the risk. For example, there is an area called the Hogshooter that has the potential to heave shale slivers. They are light gray, flat pieces of shale, but there are enough of them that they are easy to spot on the monitor even if we are busy with something else.”

The company also places cameras throughout completion, flowback and production operations. “Each camera acts as another set of eyes to check for any anomalies,” Hatami explains. “Some of the cameras let us zoom in close to see if something looks off without needing to send anyone to the equipment when there is a lot of pressure on it.”

The completions involve cementing the casing and performing a plug-and-perf operation. “We do 200-foot stages and 20 clusters a stage, meaning we are shooting perforations every 10 feet. Then we drop diversion, with two drops for each stage,” Hatami relates. “This works well, but there is plenty of room to get better results. We are looking at changing the perforating strategy to reduce the number of holes or reconfiguring how we perforate based on the geology rather than repeating the same design in every stage of every well.”

Initially, the wells flow naturally up the tubing. As the pressure declines, most go on gas lift, Hatami reports. “We prefer gas lift because we can address most issues from the surface, which keeps costs and risks low,” he says. “The Anadarko Basin has plenty of gas pipelines, so we rarely need to worry about getting a sufficient supply.”

During production, cameras once again support other technologies. “We put the cameras on movable stands and place them in various positions on our locations where they can monitor our operations, wellheads, compressors, vessels or tanks,” he says. “If data from our SCADA systems suggests something is off, it only takes a few seconds to put eyes on it. With the cameras’ sound and visual information, we can often diagnose issues faster, reduce costs and risks, and improve production.”

Low-Cost Operator

With 217,000 net acres in the Anadarko Basin that are largely held by production, include both oil and natural gas intervals, and have ample takeaway capacity for both commodities, Canvas Energy has the flexibility to adapt to commodity price shifts, says Chuck Duginski, the company’s chairman and chief executive officer.

“Our business plan is designed to be self-sustaining,” he comments. “To avoid drilling ourselves out of business, we work hard every year to bring in more undeveloped locations than we drill. Sometimes that can govern our pace of drilling, but since we adopted our current strategy, we have exited each year with more undeveloped locations than we started.”

Duginski credits that success primarily to the company’s staff. “We take care of our people and develop them,” he says. “As a result, we have excellent production, drilling and completion operations, as well as experienced geologists, engineers and dealmakers that can continuously feed the front end of the development machine.”

From 2018 to 2022, Canvas Energy cut its per-barrel lease operating expenses by 43% and its drilling and completion costs by an average of 15%-20%. Canvas attributes this progress in part to a process for collecting ideas from employees across the company.

From 2018 to 2022, Canvas reduced its general and administrative costs for each barrel by 48%, its lease operating expenses for each barrel by 43% and its drilling and completion costs by an average of 15%-20%, Duginski reports.

“To reduce our G&A costs, we moved into a smaller office,” he relates. “We learned during Covid that many of our employees could, and in some cases preferred to, work remotely, and the lease on our previous office ended at the right time to give us a chance to downsize.”

Many of the company’s improvements come from ideas submitted by pumpers and other field hands, Duginski notes. “In 2020, shortly after I joined, we put in place a process to collect ideas from throughout the company, evaluate them, and act on the ones that make sense,” he says. “For example, we have made incremental changes to our production facilities that eliminate unnecessary equipment, reduce the chance of a spill and cut emissions. Some of the most impactful changes involved switching or optimizing artificial lift methods to minimize failure rates and costs.”

According to Duginski, employees have been happy to submit ideas in part because Canvas values transparency and honesty. “Since I joined in 2019, the management team has been very open with our employees about both the business’s challenges and successes,” he says. “From our financial restructuring in 2020 to how we navigated the pandemic years, we have been upfront with our employes, shared a lot of information with them and asked them to help us address our challenges. They have responded well to that.”

Duginski adds that the management team strives to make two-way communication with employees a matter of course. “I frequently drop in on meetings to see how operations or other processes are going and to give employees an easy way to talk with me,” he comments. “I have an open door policy as well. And two or three times a year, we hold townhall meetings where employees can ask questions. The questions are anonymous to avoid any hesitancy about challenging management.”

Duginski says frequent communication has helped the leadership team understand employees’ concerns, what is going well and where the company may need improvement. The Oklahoman named Canvas one of the top small businesses to work for in 2022, an award based on anonymous employee surveys.

Partnership Orientation

In addition to taking care of its employees, Duginski says the company tries to be an excellent partner to service providers. “We work very hard to be an operator of choice for the companies that work for us,” he reports. “We provide long lead information so they can manage their supply chains and logistics efficiently. The resulting savings often make their way to what we see on the invoice.”

According to the company’s investor presentation for the fourth quarter of 2022, the 20 laterals Canvas brought on line last year had a projected rate of return above 100% based on the NYMEX prices for Jan. 31.

“Today, we are drilling with one rig and expect to maintain that level of activity throughout 2023,” Duginski says. “However, we have the flexibility to pick up a second rig if pricing is favorable and our cash flow supports that. If prices turn in the other direction, we also can lay the rig down and wait for better pricing. This industry is volatile enough that we avoid long-term commitments on drilling contracts or pipeline arrangements so we can control the pace of our activity.”

The company also takes a deliberate approach to developing its acreage, most of which is in Oklahoma. “We drill in three areas: Canadian County, Kingfisher County and the Glass Mountain area on the basin’s north side,” Duginski relates. “Canadian County has been our area of focus for the last two years of drilling, so it is very well understood. In 2022, we began pivoting more toward Kingfisher and Glass Mountain. We had enough inventory that we could drill a development well, then move the rig to another area while we assessed what we learned.

“Today, we have a deep enough understanding of the geology in the new areas, as well as how to drill and complete the wells, that we can move to more continuous development and consistently deliver outsized returns,” he says.

Opportunistic Acquirer

Public companies’ emphasis on fiscal discipline and returning cash to shareholders will create opportunities for smaller players, suggests Robert L. Lynd, president of Alvarado 2014 LLC, the operating subsidiary of Alvarado Minerals LLC, a privately-held company that aims to grow distributions for its owners. “With large public companies focusing less on production growth, drilling and development activity is materially lower than it was just three years ago,” he observes. “Given many plays’ high initial decline rates, the reduced investment eventually will shrink supplies enough to increase prices.”

To take advantage of the anticipated price increase, Lynd says Alvarado plans to “be as aggressive as we can be to get long on the commodity.” Even so, he says the company is selective about where it puts capital. “To invest, we need to expect a 30% rate of return across the life of the well and get our money back within two years,” he details. “Ideally, we like to double our investment on any opportunity we pursue.”

Finding such attractive opportunities can be tough, but Lynd predicts bright days ahead. “I would not be in this business if I was not bullish on long-term commodity prices,” he remarks. “We make most of our investments with the expectation they may not be developed in a year or two, which means they will benefit from a different commodity price environment.”

Alvarado Minerals LLC is finding opportunities in Oklahoma and Texas that pay back the investment within two years and deliver respectable returns. In addition to developing the Hoxbar Marchand, the company says it is building a position in the Eagle Ford Shale.

The company’s search focuses on Oklahoma and Texas. “Both are business-friendly states that have supported oil and gas for more than a century. They have a mix of opportunities that are under development and legacy horizons that have yet to be pursued with modern technology, so we are confident we can make money in them,” he explains.

“But we do have to consider the cost of entry,” he allows. “It would be tough for a company of our size to do a deal in the Midland or Delaware basins because they are the hottest plays in the country and potentially the world. We have been far more successful building positions in areas that are not the flavor of the month.”

Despite Alvarado’s penchant for stepping off the beaten path, success requires patience, Lynd notes. He points to the Hoxbar as an example. “In late 2015 and early 2016, we were hunting for opportunities in the Verden Field area of the Hoxbar trend outside the town of Chickasha, Ok.,” he recalls. “Unfortunately, the core of the play is small at only about 20,000 acres, which meant competition was fierce. We were able to participate in the play, but only through a small nonop position with the two larger operators who dominated leasing.

“But we kept our eye on it and waited,” he continues. “The returns in the Hoxbar are attractive, but because it’s a conventional play with a small footprint, many operators eventually decided to chase acreage elsewhere. By 2019, we were able to secure leases in an undeveloped area, a donut hole surrounded by successful wells. Since then, we have expanded our position through a trade. Our most recent well was in the area, and it has been our most successful operated well to date.”

The well used a mile-and-a-half lateral to unlock a Lower Marchand tight oil sand within the Hoxbar, Lynd describes. “We restricted production to maintain pressure and maximize the well’s long-term potential, so the initial production is not inspiring. But look at the first three months: It’s a very, very strong well relative to the offsets,” he enthuses.

Eagle Ford Appeal

Alvarado’s budget for the year initially included another well within the Hoxbar trend targeting the Medrano, a gas sand above the Marchand oil sand. “Since we put that well in our budget late last year, gas prices have dropped significantly,” he notes. “We are evaluating our options to drill an oil well instead.”

That well may be in the Eagle Ford. “I have had an interest in the trend for a long time, but until recently, the cost of entry was too high for it to make sense for Alvarado,” Lynd comments. “However, we had an opportunity last year to buy producing wells in Atascosa County, Tx., that were originally drilled by Marathon. We have done some leasing since then that we hope will let us drill a multiwell pad. That could happen as early as August.”

Lynd mentions that the company is looking at other acquisition opportunities, including one that will provide several years of drilling inventory. As in the Hoxbar, Alvarado is playing the long game. “Some areas of the Eagle Ford, especially the southern part, are much gassier. In today’s price environment, we see an opportunity to build a position that we can develop when gas prices get back above $4.”

The leases the company pursues often require extra work, such as unraveling complex titles, Lynd relates. “Given our size, we can spend time on a single drilling opportunity in an attractive area because it will be meaningful to us,” he reflects.

As it leases, Alvarado evaluates nearby properties with limited activity or other signs of potential upside. “If we think they might be worth acquiring, we will reach out to the operator. As a show of seriousness, I send our estimate of the property’s reserve value, assuming they own 100% and a lease net revenue interest common for the area. That helps us get behind the curtains under confidentiality agreements and see the lease operating statements and revenue statements so we can tighten our valuation.”

According to Lynd, closing deals tends to be difficult. “When prices are low or modest, as they are now, it’s tough to find motivated sellers because they are comparing the bid to one they could get when prices are high,” he explains. “To compensate for that, I tend to make more aggressive offers than I would in a high-price environment.”

When prices are strong, the company may only meet its investment criteria if its offer discounts the present value of the producing asset by 20%, Lynd illustrates. “In a low-price environment, we can give more consideration to the intrinsic value of the producing asset at the time, using a discount of 15% or less and making a bet on the commodity,” he contrasts. “Sometimes that helps get deals done, but nine times out of 10, we are unsuccessful.”

Over time, Lynd assures, the work pays off. “Rarely does Alvarado enter a basin at a cost of entry greater than $1,000 an acre,” he comments. “In many cases, we get into areas for hundreds of dollars an acre that later require thousands.”

As an example, Lynd recounts that the company picked up nonoperating interest in the Midland Basin around 2013, when the Wolfberry was being developed vertically. “We signed or acquired leases in that trend with the expectation that it would be developed horizontally,” he says. “We paid about a twentieth the cost we would today, and we have an override.”