With ESG becoming the new EBITDA in the eyes of stockholders and investors, environmental companies—as the “E” in ESG—are finding more interest in their services. That’s helping them somewhat in weathering what is becoming the “Year of the Black Swan,” 2020.
Others are combining that with creative ways to leverage accumulated data to improve services to customers.
Such was the revelation for engineering giant Terracon regarding its 50-plus-year trove of historical data. The 1965-founded company, which includes environmental services, engineering, and more in its repertoire across multiple industries, realized it had “an unbelievable mass of data” scattered among its 150 offices, said the company’s Erin Loyd. Loyd is principal and office manager at Terracon’s Lubbock office, which services the Permian Basin. Five decades of surveying thousands of sites for geology, topography, rights-of-way, and other information had amassed a data base with incredible depth and breadth of information.
The company’s geotechnical department had the vision to merge those individual databases into one, make it searchable and available. They then merged it with publicly available information to extend its depth even further.
“When you put all that information together, it becomes a very powerful data mining asset,” Loyd said.
A product called Stage1 was the result, released incrementally starting in early 2019. It provides a fast and inexpensive way for clients to get preliminary information on prospective sites for drill pads, pipelines, commercial locations, and any other construction project. While its main focus is on engineering, Loyd said an environmental survey aspect is being phased in.
“Environmental planning is the process around gaining permitting and mitigating the risk within permits for, let’s say, a linear project like a pipeline,” Loyd explained. Stage1 will allow a business to quickly do a preliminary evaluation of waterways to be crossed, presence of endangered species (what Terracon calls ‘bugs and bunnies’), among a total of approximately 50 categories to be evaluated. The program will save a great amount of time and cost in this process.
Once a selection has been made, there is still the need for in-depth onsite evaluation.
For Terracon’s overall business, drastic pricing events of Spring 2020 have shifted some business flow—but because it provides a wide range of services, it is managing well, said Mike Adams, Terracon’s National Program Director for its Oil and Gas Services division. “We do a lot of work on the front end of new projects, but at the same time we’re also providing environmental services on ongoing projects, [and] we’re still seeing regulator-driven activity continuing. Many of our clients are opting to wait to make investment decisions until the price environment improves.”
The Permian, as is often the case, is doing better than most in Terracon’s oil and gas business. Adams attributed that to the Basin’s long-term infrastructure investment. “Pretty substantial investment has already been made in pipeline takeaway capacity.” He continued, “I think the infrastructure in the Permian allows for folks to move oil to market more readily and probably more cost-effectively than some of the operators working in some of the other basins.” He was referring specifically to the Bakken’s challenges with Dakota Access Pipeline court rulings in July.
Some work continues in exploration and production, although more limited than early in 2020. Previously-scheduled projects such as small scale pipeline gathering systems are continuing, for the most part.
Much of the environmental work must go on regardless of commodity prices. When asked if low prices had led environmental clients to delay work or ask for it to be done at lower cost, Loyd said producers are generally evaluating environmental issues on a larger scale than just cost.
“Over the last two-to-three years there’s been a theme of, ‘Let’s continue to be good stewards but let’s be good scientists at the same time,’” Loyd said. As soil and groundwater conservation continues to grow in importance, both locally and nationally, the industry is moving away from simply removing and disposing of contamination. New technology, including microbes, oxygenation and more have created cleaner and more cost-effective options on “the physical portions of it.”
“Now they’ve taken it to the next level in the utilization of GIS and mapping and tracking essentially release inventory and how quickly you can move to get solutions to get those out the door,” he added.
An established California waste processing company thought it had an opening for bringing its environmental solutions into the Permian Basin market in March, having scheduled some test runs.
Then COVID-19 shutdowns hit, with the associated oil price crash. Now they’re on hold indefinitely, said the company’s Mike Umbro.
The company, RL Environmental, is established in the Golden State’s largest basin, Kern River, where it’s operated for about five years. Umbro is the firm’s VP of corporate development.
Breaking into the Permian, even though the two areas share a number of producers among the majors, has been hard.
“We were about to start pilot work with some major operators out there in March, then COVID hit and the crash hit. We have had sizeable Permian operators come out to Bakersfield and see our operations.” Umbro noted that many people consider California as a whole to be radically different from Texas, but the central valley area is different from the most-heard voices on the West Coast. “I call Bakersfield ‘Midland West’ because, save for a few differences, it’s the same tight-knit community, same struggles getting in with new operators.”
RL Environmental handles 13 onsite waste streams, including drilling fluids, foam returns from workovers, and cement water from well abandonments, as well as maintenance and D & C type fluids. In California, Umbro said, all sites use closed-loop drilling instead of open pits.
The company provides three main services. First, “It’s really turnkey fluids processing where the focus is on recovering any valuable resources out of that waste stream,” Umbro explained. “Second is de-watering that material so you’re minimizing the waste going to injection or disposal wells. Third, it’s processing water to a spec that is desired by the operator for beneficial reuse.”
Umbro sees a payback in recycling rather than simply disposing of spent fluids and other oilfield waste. “Typically, if there’s oil in that waste stream, we’ll recover enough product to pay for the service, so you’re getting the oil recovery, you’re eliminating trucking off-lease, you’re eliminating your footprint leaving the lease and it’s cost-neutral.”
In this price environment there is some concern about the cost benefit. “I see a lot of oil just being thrown away, and there’s argument from the operators (saying), ‘At low oil, is it really worth my time to try to recover that oil?’ which is a valid point.”
As a whole, he believes the industry is indeed changing its thinking about disposal versus recovery, and some of that is connected to the increasing interest in ESG. “I think what we’ll see in the oil industry is kind of a re-thinking of how we’re developing these massive plays and I think we’ll probably see folks really focus on the infrastructure and design of process, hopefully, [instead of] just drilling wells and looking for the success and IPs.”
Houston-based Milestone Environmental Services operates nine disposal sites, most of which are in the Permian, with two in the Eagle Ford. Facilities include two oilfield waste landfills, one at Orla and the other in Upton County.
Company president and CEO Gabriel Rio described their services as follows: “We’re a comprehensive oilfield waste management firm. We do dispose of some produced water, but it’s a very small piece of our revenue stream. Our bread and butter is disposal of dirtier waste streams—dirty fluid including spent water-based mud, oil-based mud, tank bottoms, fluids that are sucked up out of reserve pits before they’re closed.” They also handle other waste that might be delivered in a vacuum truck.
For a company whose bread and butter involves disposing of drilling products, the current crisis is indeed a challenge. “This is the first time in my career—and I’ve been in this business for 15-20 years—it’s the first time where I’ve seen production shut in on a large scale. I’ve certainly seen drilling activity ebb and flow, and Milestone has survived through several cycles. But this is the first time we’ve seen, number one, the drilling contract at such a fast pace—and, number two, the actual production shut in on a significant scale.”
Milestone’s top revenue streams come from drilling waste, remediation, and production, in that order. A small amount comes from completions.
“We have certainly seen a slowdown at all of our facilities, in the Eagle Ford and in the Permian, particularly on the drilling side,” Rio said. A small uptick in remediation has helped, which he attributes to the fact that the firm’s landfills used in remediation were new enough to continue in growth mode even during the downturn.
A small recovery in oil prices has yet to result in a return to drilling because, he observed, “Our customers really are being very, very conservative in regard to their spend and their budget” in order to avoid overreacting to positive pricing. Some of that conservatism is due to the drying up of new capital, a drought that was already building up before the COVID-19 quarantines. Rio hopes to see drilling activity begin to recover in the latter part of 2020. Smaller independents, however, may take much longer to spend money on new wells. Meaningful drilling increases may not happen until 2021, he said.
Eagle Ford business, where in July there were fewer than 10 active rigs, has been hit particularly hard, while business in the Permian’s Delaware Basin is better than anywhere else for Milestone. The business they do have in the Eagle Ford is related to ESG.
“One of the drivers of our business is the environmental behavior of our customers,” Rio noted. “If our customer decides that they don’t want to bury their waste onsite, and they don’t want the ongoing liability and the negative carbon footprint that comes with laying oily waste out on the ground and letting it evaporate—if instead those customers decide that they want to use closed-loop methods and not put that waste on the ground to begin with—that’s where we derive more demand for our services.”
Rio pointed out that untreated drilling waste spread out on land—or landfarmed, which is allowed in Texas but not in New Mexico—includes some oil products that evaporate into volatile organic compounds—VOCs—that are greater greenhouse gases than CO2. By separating out as many hydrocarbons as possible and injecting them into appropriate formations underground, Rio said, the carbon footprint can be reduced significantly.
“We calculate [that] the carbon footprint of our business, because we’re taking so much hydrocarbon matter and reinjecting it, is negative to the tune of several hundred thousand metric tons per year of CO2 equivalent,” he stated.
In previous years the only companies doing closed-loop drilling were in places where pits were impossible, such as southern Louisiana. Now, Rio sees the percentage of closed-loop wells at closer to 50. “Our customer base is really starting to wake up to the fact that environmental practices, and their ESG score, are going to be a significant driver for how they get capital.”
For some cash-strapped smaller operators, ESG concerns currently take a back seat to staying in business—companies that are, in effect, “living paycheck to paycheck”—but better capitalized clients are embracing ESG actions even in the downturn.
Paychecks for everyone may continue to be in peril for the near future in the environmental end of the oil gas sector, but those who watch their cash flow and who continue to innovate may have a better chance of survival than most.
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Paul Wiseman is a freelance writer in the oil and gas sector.