Canada / Gulf Coast / Mid-Continent / E&P / Northeast / Rockies/Other / Shale Daily / NGI The Weekly Gas Market Report / NGI All News Access

E&Ps Able to Chart Destiny, All Basins Being Equal, Says BTU Analytics

The wellhead economics are not that different across the entire U.S. onshore, but how individual producers are digging in has made all the difference, according to a deep dive by BTU Analytics LLC.

Analyst Corey Boettiger and consulting partner Kathryn Downey held a webinar last Tuesday to discuss how domestic exploration and production (E&P) companies are coping in an ever lower-cost and still low-priced environment.

E&P companies today actually are able to "chart their own course in this environment," Miller said. "With prices where they are today and where we expect them to be in the future, producers that can really execute on having the lowest cost will be able to have sustained production and sustained activity in the field."

Based on BTU's data, the wellhead economics of the various onshore basins "really don't look that different," she said. Referring to the oily leaseholds, she said "there usually is the 'best of the best,' and the best of the best break even at prices under $40/bbl. And then there's a lot of production and wells that came online that didn't meet those standards."

The better operators are culling their leaseholds, pushing aside the less productive, more costly acreage to zero in on the wells with the better economics. And those wells can be found anywhere, not only in the Permian Basin.

Producers not working in the heart of the Permian’s Midland sub-basin, within Oklahoma’s prolific stacked reservoirs or in northeastern Pennsylvania still can be part of the "supply stack going forward," Miller said. "It really is the core of each of these plays competing with the core of all the other plays in North America."

Other things factor into whether a producer is going to be a success down the line, such as expanded infrastructure in a region and internal hedging, according to BTU's research. New oil and gas transportation projects, for example, impact differentials and netbacks, and contribute to production economics going forward.

"Just because we have certain basins that look like they're on top today, it doesn't mean that a project or several dozen new projects won’t change that going forward," Miller said.

Because the U.S. unconventional revolution has changed global energy dynamics, the path that independent producers take is the one the market will travel as well.

"Where independents go is really where the market goes," Miller said. "The growth came from the independents...and the decline came from the independents. So when we talk about who's hedged, how much are they hedged, when we talk about new projects, the economics of individual producers, that's important because that's really the leading edge of what's driving overall supply of crude oil and natural gas."

The world's thirst for oil and gas is slowing, but supplies keep increasing.

"So what does a producer to do, given this outlook for potentially slower demand growth as well as a supply outlook that has many more potential producers such as OPEC and Russia competing for that supply? Obviously, producers are going to focus on what they can control, and those are costs."

The huge improvements in well economics have allowed producers to continue to produce even at low prices, Boettinger said.

"It really boils down to decreases in costs and increases in productivity." For example, many operators are renegotiating their gas gathering contracts to reduce costs, something that is paying big dividends.

In the gassy Haynesville Shale, for instance, BTU found that a decrease in gathering costs from 2013 to 2016 resulted in an additional 10% of wells becoming economic at the $3.00/Mcf mark, Boettiger said. "This is a really big improvement in bringing down one aspect of these costs."

Basins vary, but there is no set cost number for any one of them.

It's true that well economics are "coming down faster and more aggressively" in some places than in others, such as the central area of the Permian's Midland sub-basin. The sharp reduction is a major reason many operators are moving aggressively to acquire leaseholds.

After factoring in basis differentials, the Haynesville and neighboring Cotton Valley sands in East Texas also "are looking competitive compared to the Northeast" because of transportation constraints that still exist in Appalachia.

All in all, though, "there's no play here that stands out as totally unfeasible," Boettiger said. "A lot of it has to do with the operators that are working within that play; they are responding to changes." While some basins look better than others, "it's not the play that you're really seeing big differences in." The Bakken Shale's output has fallen, but the reasons are better traced to a lack of transportation to move crude there, while it's much easier from the Permian.

"None of these plays jump out as totally off limits for drilling," he said. Patterns have emerged within various basins about what part of the acreage is "good" for drilling.

Still, "it's not the basin that's the determining factor about how well an operator can do...Transportation is really going to weigh heavily on the economics."

According to Miller, there are plenty of wells now breaking even "in all of these plays...Inventory really isn't an issue."

Prices likely are going to be low for some time, with gas estimated to average sub-$3.50/Mcf and crude sub-$60/bbl. If growth is going to be slow because prices are stagnant, the crux is "really about shutting out some of those marginal operators," she said.

The age-old story of having a better balance sheet is a determining factor of what E&Ps will succeed.

Producers buying land in the Permian appear to have no problems accessing the capital markets, with an 45% of the capital raised in the last two years, according to BTU. The Northeast accounted for the second-most in capital raised at 25%, while Oklahoma's stacked reservoirs accounted for about 9%, the Bakken 6%, the Niobrara formation 5% and "other" leaseholds taking 10%.

In this environment, growth for U.S. producers "is fleeting for most," but there are things to control, said Miller. Some E&Ps already have their operations managed to grow, while others are managing the "right" acreage. The better ones "have figured out how to keep costs low, they are putting hedges in place...They are controlling their own destiny."

Recent Articles by Carolyn Davis