Shale Investors Take New Direction

Are the days of achieving the highest possible IP rates over? Are investors now more interested in long-term well productivity than short-term payback? If so, can producers respond to what investors want?
By Patrick C. Miller | February 09, 2018

Not long ago, word of ever-increasing initial production rates from new wells drilled by operators in U.S. shale plays was music to investors’ ears.  The higher the flow rate of crude, the faster the rate of return on their investment.

But that standard of success began to lose much of its appeal in the latter half of 2017 and into early 2018 when investors began to push back against the business models of shale operators. They charged that profits from increased production were plowed back into new capital expenditures as a means of continuing to raise production, leading to negative cash flows and higher debt. It was, some claimed, an unsustainable model that wasn’t attractive to investors.

This triggered a spate of stories in the business media about investors openly expressing dissatisfaction with the shale oil and gas industry for employing risky financial strategies and structures that rewarded growth rather than profit and investment returns, which is what investors now say they really want.

“The winds, they do change,” proclaims Robert Watson, CEO of San Antonio-based Abraxas Petroleum Corp., which has operations in the Bakken, Permian and Eagle Ford shale plays. “It’s certainly a new way of looking at the industry.”

As Watson explains, “It went from the land grab issues in the early part of this decade where people were spending inordinate amounts of money on acreage and then not having the capital to develop it,” he says. “Investors really want companies to generate good economics which, for the most part, means living within your means, spending cash flow or below cash flow and using any free cash flow to do something good for the shareholders, whether it’s pay off debt, buy back shares or even pay a dividend.”

Still Pulling Hard
Not all shale operators have abandoned the idea of achieving the highest IP rates possible on new wells, however. 

“It certainly depends on the company’s strategy,” says Jonathan Garrett, research director for Lower 48 upstream with Wood Mackenzie in Houston. “Some companies—EOG for example—are interested in having the well pay back as quickly as possible. Essentially everything, once it’s paid back, it’s just upside,” Garrett says. There’s less of a concern with actual estimated ultimate recoveries as opposed to payback—shortening that payback period as much as possible. That’s why oftentimes you’ll see EOG wells being pulled really hard like an open choke whereas, if you look at Hess in the Bakken, they’re more interested in maximizing value per drilled spacing unit.”

Garrett notes that there are technical reasons why producers might want to avoid achieving the highest IP rates possible from a newly drilled well. “We can flow it as hard as we want and we’ll have a really strong, flashy initial production rate, but from a reservoir management standpoint, we could be pulling on that well so hard that we actually prematurely close up some of those fractures that we created. Or we start to pull proppant into our perforations and then that well would decline far faster than if we had a more optimized approach for managing that flow.

“There’s a lot of levers that you can pull,” he continues. “You don’t necessarily want to pull that well so hard and so fast that you close up fracks, you get screen-outs or, in some cases we’ve seen, you start producing large amounts of water prematurely because you didn’t do a good job of managing production.”

Still, Garrett believes that investors are less impressed with high IP rates than they once were. “I do think that there’s a shift taking place to a more sustainable, more fundamentally sound model that’s not necessarily centered on mega-gains in production and growth at any cost,” he says.

The New View of Upstream E&Ps
As Watson observes, “It’s just a new world view that the investors have toward the upstream E&P business. The way we’ve run Abraxas is that we’ve always been more concerned with rate of return than we have for growth for the sake of growth. That’s now playing out as the way investors really want to see E&P companies work.”

Rystad Energy, an independent oil and gas consulting and business data firm headquartered in Oslo, Norway, with offices in America, has closely monitored changes in the U.S. shale oil and gas industry as it emerged from the low-oil-price environment. Artem Abramov, the company’s vice president for analysis, says that in 2017, oil and gas activity began to expand dramatically, which caused the demand for services to increase and service costs to rise.

“Service costs started growing and well costs increased, but production didn’t increase that quickly because there’s a natural lag,” he explains. “Normally it takes between four to eight months from when you start drilling a new shale well to the moment when it starts contributing to production. In this kind of transition phase, it’s natural that cash flow balances degrade quite significantly.”

As a result, Abramov says many producers posted negative cash balances during the first two quarters of 2017, which triggered an adverse reaction from investors, many of whom had also invested in shale prior to the oil price downturn.
 
“These investors never saw their money back because of the price collapse,” he continues. “That’s why investor sentiment shifted toward the direction of preferring the shale producers to work more on the cash flow balances. They’re no longer willing to see this kind of behavior when shale producers just boost production fairly rapidly at the cost of negative cash flow.”

However, Abramov notes, “You have to expect negative cash flow when industry is in a growth mode because you invest more than you receive with an ambition to get high cash flows in the future.”

As he further explains, this caused problems because the shale industry experienced a second wave of growth in 2017, and many shale investors didn’t receive returns during the first wave. Their preference now is for the industry to grow organically, funding its spending by altering cash flow, Abramov says.

Growth at Any Cost?
Watson says there was a time when investors wanted producers “to grow no holds barred,” but that sentiment has changed.

“When they sat back and saw what they were asking companies to do, they realized that they were just slitting their own throat,” he says. “What they were asking people to do, in a lot of cases, was forcing them to destroy capital—growth for the sake of growth and nothing else. Some were drilling uneconomic wells and buying uneconomic acreage.”

Garrett says many shale E&Ps are responding to investor expectations. In the past, he says the focus was on drilling, deleveraging and then distribution.

“In this new paradigm, it’s the reverse,” he explains. “It’s distribution, deleveraging and then drilling. There’s still a fear in the marketplace that the E&Ps will essentially get back to their old tricks again. They’ll start spending more than they’re taking in and keep a lid on prices.”

Instead, Garrett believes producers should follow the cliché of value over volume. If a company needs more dollars to drill, he says it should sell something to raise the cash rather than borrowing it.

“Investors want to see that companies are operating within their cash flow,” he says. “First and foremost—E&Ps borrowing money—I would say those days are over for now. That’s why you’re seeing some of these non-core asset sales. You saw Whiting sell $500 million worth of their Fort Berthold acreage in the Bakken. You saw Halcon completely exit the Bakken. You saw SM Energy sell mostly out of the Powder River Basin.

“People will either take that cash and pay down debt or use it to grow their development program organically as opposed to going out to the capital markets for that cash,” Garrett notes.

Pros and Cons of High-Grading
Both Abramov and Garrett say investors are also watching declining production in certain areas of some shale plays. Rystad Energy, for example, conducted research on the accelerated decline rate in Eagle Ford production, a mature crude play.
“From one side, it’s a normal thing,” Abramov explains. “As a play matures, you need to move outside of the core acreage or the Tier I acreage. Normally you should expect some depletion or the reservoir. On some of these results, they were underperforming. Even with expectations of low performance, they were below expectations.

“That’s why many investors pulled back from Eagle Ford and shifted over to younger, less-mature plays in the Permian Basin,” he adds. “In the Permian Basin, we had some issues with the skyrocketing gas-to-oil ratio. All these negative new trends generated some inputs. Investors were reacting very actively last year on any kind of negative news when it came to shale.”

Garrett says Wood Mackenzie is closely monitoring how long producers can continue to tap their core assets to maintain production. “Since the downturn, everyone has talked about high-grading,” he says. “Reporters and investment bankers will ask, ‘How are you guys getting through the downturn?’ And everyone says, ‘Well, we’re high grading.’

“At what point are you out of high-graded locations?” Garrett asks. “At what point do you have to step out from areas that aren’t so great, despite the fact that technology is still quite good? That’s why we’re starting to see some degradation in well performance in some of those top producing wells in 2017 as compared to 2016.”

As Garrett sees it, one of the most important questions investors can ask is how many high-graded locations producers have left that can provide a good rate of return? “You can only drill what you have,” he notes.

What Investors Really Want
Watson says the model Abraxas employs relies on the company’s top-tier acreage in the Bakken to generate cash flow for its newer operations in the Delaware Basin.

“Our Bakken operation is really generating great returns for us,” he explains. “That allows us to accelerate what we’re doing in west Texas. We’re just very lucky to be in a position that we can continue to drill within cash flow. To put it bluntly, the Dakota Access Pipeline gave us a great shot in the arm. The returns we’re seeing in the Bakken are as good or better than what we’re seeing in West Texas because of the pipeline.”

Abramov expects changes in 2018 from last year when conference calls on second quarter results were mostly concerned with discussions about cash flow balances.

“The operators were sort of promising to investors that they would try to encourage organic growth, that they would try to achieve cash flow neutrality and would not take any new debts,” he says. “We think some of the largest and most efficient operators will be able to achieve this in 2018—companies like Continental Resources, EOG or Pioneer. They all have an opportunity this year to adjust their activity to such a level that they will be able to fund their operations with operational cash flow and still accelerate production. They have already passed through the early expansion phase when they need a lot of financing.”

Watson says a positive aspect of the oil price downturn was that it caused investors to look at how shale E&Ps were being forced to operate and conclude that it wasn’t a relevant way to run a business.

“We should want these businesses to be in a position where they can weather the downturns,” he says. “The only way to do that is to be a little more prudent with your balance sheet and make sure you’re generating the maximum rate of return on shareholders’ equity.”

As Watson concludes, “Investors are looking with a tainted eye at people saying their wells are making a 100 percent rate of return—and then look at companywide rate of return on equity, which is sometimes negative. They want to know what’s happening. Why is there such a gap? They want to see that gap closed considerably.”

Author: Patrick C. Miller
Staff Writer, North American Shale magazine
701-738-4923
pmiller@bbiinternational.com