[Editor's note: A version of this story appears in the October 2018 edition of Oil and Gas Investor. Subscribe to the magazine here.]

We sometimes talk of a “tipping point,” when various factors cross a threshold and collectively gain much greater momentum than historically has been the case. Similarly, a variety of ingredients are brewing in the Powder River Basin (PRB), which—now all converging—make a recipe for rapid growth in a basin that has at times been left on the sidelines.

Some key catalysts have come together.

Overall, operators are increasingly optimistic that they can move to “manufacturing mode” as they develop the basin. Ongoing improvements are evident in established targets, such as the Frontier/Turner, Shannon and others. However, it is a growing confidence in unconventional objectives—first the Niobrara and now the Mowry—that has some E&Ps kick-starting development programs.

Add to that the fact that the permitting process has accelerated, helping operators to build an inventory of locations ready to drill. E&Ps are rapidly ramping up the rig count in the basin, which in the depths of the downturn had nearly fallen to zero. Higher activity has led to further economies of scale, including ancillary services. And capital is targeting the PRB, where more than 15 private-equity-backed E&Ps are currently operating, joining the handful of key public E&Ps.

The recognized leader in the basin, EOG Resources Inc. (NYSE: EOG), gave its seal of approval to the progress being made in the PRB with its second-quarter results, unveiling an inventory of more than 1,600 net “premium” drilling locations. The count of premium locations was spread over three zones—the Mowry, Niobrara and Frontier/Turner—and was up from a count of just 120 Frontier/Turner locations in the first quarter.

EOG has historically defined a premium location as one that provides a 30% direct after-tax rate of return at $40 per barrel (bbl) of oil and $2.50 per thousand cubic feet (Mcf) of gas.

The PRB now constitutes its third largest asset, with an estimated net resource potential of 2.1 billion barrels of oil equivalent (Bboe), according to EOG. The company has been running two rigs and one completion spread on average in 2018, and its inventory of locations represents more than 30 years of drilling at its current pace. EOG holds a position of about 400,000 net acres in the play.

Other publicly traded E&Ps, such as Anadarko Petroleum Corp. (NYSE: APC), Chesapeake Energy Corp. (NYSE: CHK) and Devon Energy Corp. (NYSE: DVN), have also planned or set in motion activity increases. Anadarko, for example, has boosted its already large acreage position, while Chesapeake has raised its operated rig count from four to five rigs and indicated it may add another rig next year. Devon is planning to double its rig count from two to up to four rigs.

Private E&Ps have long been major players in the PRB, and they, too, are in the forefront of the many new developments taking place in the basin. Anschutz Exploration Corp. plans large-scale development of at least three zones: the Turner and two targets in the upper Niobrara.

PRB NRI

Anschutz Exploration president Joe DeDominic offered a “very positive” outlook for the PRB, where recent successes included wells in the Turner Formation and the Niobrara.

“This is an outstanding basin in which to own and operate assets,” said DeDominic. “While it’s still relatively early in the horizontal development of all these plays in the Powder, it’s all very positive. Well results are exceptional, given we’re generally still at Generation 1 or 2, at most. It’s oil, not gas, so the economics are orders of magnitude better. We’re seeing multiple, stacked, economic horizons, with as many as six targets that can be drilled horizontally within the same drilling spacing unit [DSU].

“The land situation is very favorable,” he continued. “Our net revenue interest [NRI] on average ranges from 82% to 85% vs. an average of 75% or maybe less in the Permian. That difference of 10 percentage points is a lot from an economic standpoint. The midstream piece, as it stands today, is also favorable. And we’re in discussions with a number of midstream companies to stay ahead of our needs.”

DeDominic pointed to several factors that were also helping to accelerate activity in the PRB. One is a much improved federal permitting process, which no longer takes six or more months to procure a permit. A second is that the PRB has been catching up on its use of completion technologies commonly used in other basins, which is resulting in higher performing wells.

Contrasting the PRB with the Permian Basin, DeDominic noted Permian leases have shorter primary terms than federal leases and include, in some cases, Pugh clauses as well as continuous drilling obligations. “E&Ps in the Permian can’t wait; they’ve got to be out there drilling to preserve their acreage,” he said. By contrast, 10-year terms built into federal leases afford a “more moderate” pace, reducing the speed of development.

As a result, operators in the PRB in the past have had time to “be deliberate about where they are putting their investment dollars,” according to the Anschutz Exploration president. And that’s a prudent approach, given the great many horizons—a dozen or more—to choose from in the basin. The stacked pay ranges “from the Teapot all the way down to the Tensleep,” he noted.

Anschutz Exploration has been working to finalize a development plan since early this year. At its Theo Fed pad, in Converse Country, it drilled a Turner well, the Theo Fed 3571-17-5-1FH, which delivered an IP-30 of 2,187 boe/d and an IP-60 of 1,862 boe/d (87% oil). On the same pad, it drilled a lower Niobrara well that was also productive. The pad is a short distance from pre-existing Shannon production.

On its nearby Meatloaf pad, as of August, the company was partway through drilling a well targeting the Turner, down roughly 10,500 feet vertically, and extending laterally 10,000 feet. Previously, it had also drilled two wells that are producing from the upper Niobrara. Seven tanks, each holding 400 bbl, handle the two Niobrara wells’ production, which on a combined basis have had an IP-30 of 2,009 boe/d and an IP-60 of 1,825 boe/d.

The results in the Turner and, in particular, the Niobrara have been more than sufficient for Anschutz to push forward with development plans. In the southern portion of the basin, DeDominic sees an initial development plan built around the Turner and two targets within the upper Niobrara, with the Parkman, Mowry and the lower Niobrara as additional horizons to be developed in the future.

“We’ve drilled three Niobrara zones now, and have additional Niobrara wells scheduled in the wake of the initial well results. We know two zones in the upper Niobrara work economically already, and we’re in the process of improving our results in the additional Niobrara zones,” he said. “Our belief is that we have multiple targets within the Niobrara that justify multiple horizontal wells to fully and economically develop their reserves.”

Much of the PRB has yet to be tested using today’s technology, but this is changing quickly, according to DeDominic. “We’ve drilled some of our recent Turner wells in areas where there were very few horizontal Turner wells in that part of the basin,” he observed. Recent Turner wells drilled in this portion of Converse County have an estimated ultimate recovery (EUR) averaging 1 to 1.3 MMboe (80% oil).

Niobrara And Mowry Are Pervasive

Likewise, while testing has historically been less frequent in the Niobrara and the Mowry, both zones are believed to represent a huge footprint as source rocks for many of the basin’s stacked pays.

“The Niobrara and the Mowry are pervasive across the basin. They are the two sources for the bulk of the hydrocarbon in the basin,” said DeDominic. “The two are currently in the oil generation window, that is, deep enough and at a high enough temperature so the kerogen in the rock is converting to oil. If you can make these targets work with modern technology, the area to be developed in the Powder River is massive.”

As an example, the Anschutz Exploration president pointed to Chesapeake’s Barton pad, some 24 miles to the east of the Niobrara wells drilled on the Meatloaf pad. The Chesapeake well, targeting the lower portion of the upper Niobrara, had an IP-30 of 1,299 boe/d. The EUR ascribed to the well is put at 900,000 to one million boe (76% oil).

“You’ll see us and other operators testing these zones, and doing spacing tests, to demonstrate the lateral extent and the repeatability of the play. The individual well economics, coupled with the resource potential indicated by our technical work, should, in turn, attract additional capital investment,” said DeDominic. In the fourth quarter of 2018 and the first quarter of 2019, Anschutz has a mix of about eight Niobrara and/or Mowry wells lined up for drilling, he added.

Is it time for full-field development?

Confidence Is High In Economics

“We’re at that point now,” said DeDominic. “The confidence in the EURs and the economics are high, and we’re at the stage where we need to move forward. If you continue drilling standalone wells, there is a downside risk in terms of under-developing the asset, because it’s not efficient or effective to go back and infill the acreage due to parent/child pressure depletion. And if you wait a couple of years for further study, you end up pushing out and reducing the present value of the asset.”

Covering an area that measures 12 by 8 miles, Anschutz Exploration’s initial plan in its Converse County development is currently to have a combination of four wells targeting the Turner and 16 wells targeting the Niobrara per 1,280-acre DSU (a total of 20 wells off two pads per DSU). The Niobrara wells will be completed in two of a possible four zones, depending on the area.

Anschutz Exploration estimates it has more than 1,000 net core locations targeting Turner, Niobrara and Mowry zones on its acreage in Converse and southern Campbell counties alone.

Anschutz Exploration has indicated that, at a current well cost of $8.5 million (including hookup, facilities and, later, artificial lift), a Turner well can create a PV-10 value (present value discounted at 10%) of a little more than 2.5 times its cost, assuming West Texas Intermediate at $55/bbl and natural gas at $3. DeDominic expects these well costs to come down as full-scale development takes off, narrowing the gap with EOG’s cost structure.

Takeaway Issues

In terms of takeaway, all of the Anschutz Exploration wells completed as producers in 2017 to 2018 have been hooked up to pipelines, both oil and gas, in as little as three days, according to DeDominic. A scarcity of takeaway is “a common misconception,” he said. “We’re not too far from existing infrastructure. And our strategy is to be ahead of the game in terms of facilities, electrification and having the pipelines ready to go.”

Last August, Anschutz Exploration offered various growth forecasts, depending on the future number of rigs it employs, and assuming a “single-zone” scenario based on developing just the Turner Formation. The net production estimates related to only the southern portion of the basin and excluded nonoperated activity.

From a recent base of 4,600 boe/d, net production would reach 12,000 to 15,000 boe/d in the first quarter of 2019, assuming a two-rig program in the second half of 2018 (for 1.5 average rigs in 2018). As the rig count is raised to an average of 2.5 rigs in 2019 and four rigs in 2020, net production would grow to roughly 70,000 boe/d, on average, in 2022. A six-rig program could boost output to as high as 100,000 boe/d over the same timeframe, added DeDominic.

Based on the 12,000 to 15,000 boe/d estimate for early next year, Anschutz Exploration would be generating free cash flow in the second quarter of 2019, according to the forecast.

A lot can happen between now and 2022, but what’s the confidence level about early 2019 output?

“We’re right on schedule to meet that forecast,” said DeDominic.

A New PRB Record

Wold Energy Partners has been operating in the PRB for decades, and its long legacy helped form the foundations for a firm that can now boast of having some of the “most flexible assets in the basin,” according to CFO Court Wold. The assets are proving their worth, delivering a Frontier/Turner producer recently that had an IP-30 of more than 4,800 boe/d, a new record for the PRB.

Wold Energy was established in Casper in the 1940s and is run by CEO Jack Wold. At one time involved in a diversified minerals and energy platform, today the company’s focus is virtually 100% as a PRB oil and gas operator. With headquarters now in Denver, the firm has a blend of characteristics: family legacy, nimble, quick adopter and well-capitalized, with institutional partners that include NGP.

The company undertook a strategic review of Rockies basins in 2012 to 2014 and decided to “make a shift to become a pure-play operator in the Powder,” recalled CFO Court Wold. “We have a very different business model now. We had to adapt, and our nimbleness enabled us to compete in a capital-intensive industry with the complexity of unconventional operations.”

Simultaneously, Wold did an appraisal of its legacy PRB assets, studying the rock from a technical perspective in light of results attained by other players in the basin, he added. From the study, it drew an outline of an area it defined as its “Tier 1 focus area,” and then began a process of consolidating its acreage position from what was a “scattered legacy footprint” previously.

“We recognized the resource potential in Converse County,” said Jack Wold. “We went through a multistep approach to selectively divest noncore assets in order to re-invest in the core of the basin during the downturn. We’re now 100% focused on oil and gas in this southern part of the Powder River, which is now showcasing its huge potential, particularly with new technology.”

Approximately 200 Transactions

The consolidation process, through a series of swaps and acquisitions, involved roughly 200 transactions during five years, in an effort to expand the scale of its operations, according to Jarred Kubat, Wold’s vice president of land, legal and regulatory. Wold now holds 145,000 largely contiguous net acres, predominately in Converse County, southwest Campbell County and southeast Johnson County.

The effort has apparently paid off. Many of the 20-plus rigs operating in the PRB have migrated to the Converse-Campbell border area, what he calls “the heart of our acreage position.” The firm has received “more nonop proposals today than we’ve ever had in the past,” according to Court Wold. “And we look forward to participating in those programs with our neighbors and partners.”

In terms of permitting efforts, Wold ranks as the largest holder of state permits among private E&Ps in the PRB. From the outset, according to Kubat, its permits “have been set up in anticipation of pad development. In addition, they’ve been set up for ‘cube development,’ because we understood that’s how the resource is ultimately going to be most efficiently recovered.”

Far from being content to collect permits, Wold has recently been “involved in a substantial drilling program, and we’ve have had some tremendous success there,” he continued. “Those permitting efforts have set up optionality from the standpoint of choice of formation. At this point, we likely have the most flexible asset in the basin, with an ability to accommodate drilling year-round.”

A Shift To Pad Development

As it moved into pad development, Wold looks to have set a new record for the basin with a 30-day IP of 4,811 boe/d by a well on its Tuesday Draw pad in Converse County. The well, one of a five-well program focused mainly on the Frontier/Turner, had an IP-30 production average of 2,717 bbl/d, 771 bbl/d of NGL and 6.2 MMcf/d. First production was in mid-June and, after 60 days, was still flowing more than 2,000 bbl/d of crude oil (42 API).

“It’s a very exciting well,” said Jack Wold. “It can compete with anything in the country right now, and we have a sizeable queue of similar locations to tackle as we shift to pad development.”

Remarkably, on the same Tuesday Draw pad, Wold previously completed a well with “excellent results” from the shallower Shannon Formation. The well had cumulative production of about 190,000 bbl of oil during a period of 18 months.

How are Wold’s plans for full-scale development progressing?

“So far, our permitting plans call for four wells in each of the horizons: Sussex/Shannon; Frontier/Turner; Niobrara; and Mowry,” said Jake Phipps, Wold’s operations manager. “We’ve seen others go up to 16 wells in the Niobrara and Mowry in a 2-square-mile area. We’re excited to see that level of development.”

According to Phipps, most key factors are falling into place in the PRB.

“The momentum is swinging in our favor, with now over 20 drilling rigs in the basin and the midstream companies coming in,” said Phipps. “We’re seeing more and more oilfield service companies moving into the area, as well as infrastructure for sourcing water and frack sand. These and other factors are driving costs down and efficiencies up. With the increase in EURs at the same time, it’s really an exciting time for this basin.”

Portfolio Of Premium Locations

EOG has yet to unveil some of the exact details of its development plan for the PRB, but the company is clearly preparing to shift to a higher gear in terms of its level of activity in the basin. And with a net resource potential estimated at 2.1 Bboe, the PRB “is poised to become a major asset in EOG’s diverse portfolio of premium plays,” the company said in second-quarter earnings release.

Like others, EOG had previously focused on established targets, such as the Turner, where it counted some 120 premium locations. But with its second-quarter earnings, EOG expanded its premium inventory by upgrading to premium status both the Niobrara and Mowry. This added 555 and 875 locations, respectively, to its premium inventory. In addition, the Turner inventory rose to 200.

In total, EOG said its 2.1 Bboe resource potential in the PRB was comprised of 1,845 net locations with an average 70% working interest and 58% NRI. The company had operatorship of 85% of its “core premium” acreage, it added, and recent trades consolidated an additional 90,000 net acres. Running an average of two rigs, EOG aimed to complete 45 net wells in 2018, up from 39 last year.

Picking Up The Pace

At its current pace, the premium inventory represents more than 30 years of drilling, but EOG plans to pick up the pace in the not-too-distant future.

“As far as the Mowry and the Niobrara go, we’ll be increasing activity in 2019 on those plays,” said David Trice, EOG’s vice president of exploration and production, on the company’s call. “The volume impact of those will be more likely weighted to late 2019 and into 2020, as we build out our infrastructure.”

To date, EOG has drilled nine Niobrara wells and nine Mowry wells since it began targeting the two source rocks in 2008 to 2009. With proprietary cores coupled with public data, the company has built full petrophysical models, which has allowed it to identify the best targets and assist it with its completions. This has been “really critical to the success of the plays,” according to Trice.

In addition, bringing down well costs has played a major role in improving the economics of the PRB. For example, 2-mile Turner wells are “routinely” drilled in six to seven days, and up to 10 stages per day are completed in the company’s zipper frack operations, noted Trice. “We’re a lot better at executing in the PRB,” he said, citing improved drilling and completion, facility and lease operating costs.

“Sustainable cost reductions and shorter cycle times, driven by efficiencies, were a big contributor to adding these two shale plays to our PRB premium inventory,” observed EOG’s CEO, Bill Thomas.

Overlap means less surface disturbance

As shale resource plays, the Niobrara and Mowry offer great potential for efficiencies in the future, according to Thomas. Tight downspacing is a “great fit” for drilling large packages, using multiwell pads, long laterals and zipper fracks. Moreover, since the two plays overlap on “much” of the EOG acreage, they can be co-developed, resulting in less surface disturbance and a reduced environmental footprint.

Recognizing that the degree of overlap is not perfect, EOG’s acreage position in the Niobrara is not as big as its Mowry footprint. Close to 100% of the Niobrara is expected to be co-developed with the Mowry, according to Trice. And viewed from the opposite direction, about 60% to 65% of the Mowry is likely to be co-developed with the Niobrara, he added.

EOG has roughly 140,000 net acres prospective for the Mowry. Assuming 880 total net locations, at 660-foot spacing, this translates into an estimated resource potential net to EOG of 1.23 MMboe, based on a gross EUR per well of 1.7 MMboe (net after royalty equals 1.4 MMboe). Well costs are put at $6.1 million for a 9,500-foot lateral well. The 30-day IP of two recent wells averaged 2,190 boe/d.

About 90,000 net acres held by EOG are deemed prospective for the Niobrara. Assuming 560 total net locations, at 660-foot spacing, this translates into an estimated resource potential of 640 MMboe, based on a gross EUR per well of 1.4 MMboe (NAR equals 1.15 MMboe). Well costs are put at $5.9 million for a 9,500-foot lateral. EOG cited a 30-day IP of 2,090 boe/d for the Ballista 213-1301H.

The Turner differs from the two shales in needing wider spacing, at 1,700 feet, resulting in 405 total net locations on its almost 170,000 prospective net acres. This translates into an estimated resource potential of 200 MMboe, based on a gross EUR per well of 730,000 boe (NAR equals 500,000 boe). Well costs are lower than in the resource plays, at $4.5 million for an 8,000-foot lateral well.

Hydrocarbon Mix

A notable variable is the hydrocarbon mix produced by each formation. The Mowry has a higher natural gas component, given a EUR split of 28% oil, 47% gas and 25% NGL. This compares to an EUR split of 48% oil, 36% gas and 16% NGL for the Niobrara and 46% oil, 39% gas 15% NGL for the Turner. The oil cuts in the Mowry are quite variable, according to Trice, ranging from 20% to 60%, depending on location.

Setting aside mix issues, productivity is undoubtedly strong. EOG said its average IP-30 from two Mowry wells, at 2,190 boe/d, included 5.6 MMcf/d of gas. One of the two wells was the Ballista 204-1102H. An earlier well, the Ballista 213-1301H, producing from the Niobrara, had cumulative output of 225,000 bbl of crude and more than 1 Bcf of gas since coming online in June of 2016.

With its acreage in close proximity to EOG, Navigation Powder River LLC got off to a “great start” with its first two wells in the basin targeting the Turner Formation, and president Fred Miller sees a marked change in the PRB as industry exploration efforts transition to major development programs.

“The Powder used to always be someone’s back yard,” recalled Miller. But with the industry delivering “very good well economics that are not constrained by midstream,” the basin has given “birth to a new concept development. The way I see the Powder now is it’s the Permian without pipeline constraints.”

The Navigation team is a relative newcomer to the PRB, but not to the Rockies. After a few years of working on tight gas at Devon Energy, Miller moved to Carrizo Oil and Gas Inc. (NASDAQ: CRZO) and oversaw the development of more than 100 horizontal wells in the Denver-Julesburg Basin. Miller remembers drilling the first Niobrara well in November, 2010, fracking it, and “having oil in the tanks by Christmas.”

After co-founding Navigation in 2015, and raising funding during the downturn, there was “ample time” to pore over public data and other sources on the PRB, according to Miller. “We studied over 240 Turner wells in the basin before putting any money in the ground. We spent, literally, months just toiling through that data, and the data shed a whole new light on the reservoir.”

Earlier this year, Navigation, backed by private-equity sponsor Juniper Capital Advisors, announced results from its first two wells. The first, Adam Federal 35-43-73-2H, had a 30-day IP of 988 boe/d (88% oil), or 241 boe/d per 1,000 feet of lateral. The second well, Lucian Federal 3-42-73-3H, had a 30-day IP of 1,210 boe/d (86% oil), or 275 boe/d per 1,000 feet of lateral.

Accessing Laminations

Navigation had developed a new perspective on its Turner well completions as it relates to laminations, according to Miller. Whereas other E&Ps tended to bypass them, “we definitely are accessing the laminations that exist in the reservoir,” he said. “It’s like having another reservoir.”

To explain, Miller gave the example of a Turner section that might be 200 feet thick, of which 40 feet at the top might be comprised of a “clean, blocky section,” followed by a series of laminated sections. If even only half of the remaining 160 feet was made up of good sand pay, “you’re getting almost triple the access” to reservoir rock compared to prior E&P actions.

“Some of it may not have as good reservoir properties,” he added, “but it’s still charged up, has plenty of pressure, and it hasn’t been accessed by some of the older wells. It’s still there.”

To illustrate, Navigation’s first well was drilled on a five-well per section spacing pattern, with an offsetting EOG well that had produced from the Turner for the last 2.5 years, he recalled. “It was about 900 feet away, and we saw no indications we were fracking into something that was depleted. As we brought our well on, it’s been fantastic; it’s on track to become a top percentile well in the basin.”

This makes an argument for further downspacing in certain areas of the Turner. “Operators have been sitting on the fence in terms of how to proceed with developing the Turner,” said Miller. “At first, it was two wells per section in the Turner, now it’s moved up to three to four, and with our most recent well we believe there’s clear-cut evidence it’s at least five or six wells in certain areas.”

For the balance of the year, Navigation has plans for three more Turner wells and two Niobrara wells. In one area, it sees both an A and a B bench in the Turner. In one of the benches, it expects to place four wells, with two or three wells in the other bench, depending on “how well the formation takes the frack.” In the Niobrara, it is targeting the B bench.

The Niobrara comprises “a giant swath of reservoir that’s over the majority of the Powder,” said Miller. “We’re extremely excited that we have some acreage near a couple of the hotspots,” he added. “And we have acreage that is on trend with one of the better Niobrara wells, namely the Ballista 213-1301H.

PRB Is ‘Growth Engine’

Described as its “growth engine,” the PRB is expected to drive a doubling of Chesapeake’s oil production next year from year-end 2018 levels. And as the company weighs the varied options offered by its “hotspot advantage” in Converse County, its focus is for now firmly on the Turner, where it can break even (minimum 10% return) at $25/bbl and $2.75/Mcf, according to the company.

“Right now, the Turner wells trump most other options we have in the PRB from a capital allocation perspective,” said Tim Beard, vice president, Rockies Division. “The Turner is taking the money because the well economics are so good, so prolific.”

In July, Chesapeake added a fifth rig to the Turner program. As of mid-August, Chesapeake had drilled some 24 wells in the Turner Formation, and a forecast accompanying its second-quarter results called for some 43 Turner wells to be drilled in 2018. Cycle times have improved, noted Beard, with three recent wells drilled in less than 20 days apiece vs. more than 50 days for the first Turner well.

Well costs were about $8- to $8.5 million, with a line-of-sight to sub-$7 million soon, according to Beard.

Chesapeake has indicated it may add a sixth rig next year, although exact timing is uncertain, and it may be used to appraise additional targets, said Beard. Away from the Turner, the main targets to be developed in 2019 are the Niobrara and the Parkman. The latter wells are “shallow, cheaper and have high oil cuts,” noted Michelle Hileman, geoscience manager of the Rockies division.

Chesapeake’s formula for Niobrara wells has moved to longer laterals, markedly more well stimulation and wider spacing (from 660 feet to about 1,100 to 1,300 feet). Following its success with its Barton well, stimulated with about 2,000 pounds per foot of proppant, Chesapeake tested three drilled but uncompleted wells with completions of about 2,000, 3,300 and 4,000 pounds per foot with encouraging results.

Beard indicated Chesapeake is happy to proceed in stages in developing its PRB assets over time.

Making ‘Multiple Passes’

While some E&Ps are drilling Turner wells at spacing of four wells per section, said Beard, “our thoughts are two to three Turner wells per section. Right now, we’re drilling them at two wells per section, moving to three wells per section at most.” Likewise, when it comes to developing the Niobrara, Chesapeake is contemplating undershooting peers at “four to five wells per section.”

“We’re going to be making multiple passes,” observed Hileman. “As we build our pad and facilities, we’re planning for success in the other stacked formations. After the initial pass in the Turner, we’ll return to drill additional formations, assuming commodity prices are right. And we’ll continue that process over and over again.”

As for possible interference, “from the Turner to the Niobrara, you’re talking about close to 500 feet of section between them,” she said. “Interference is not an issue.”

And when potential synergies arise, they can be captured if they make sense, said Beard, recalling an instance when Chesapeake drilled Parkman and Turner wells off the same pad. “When we drilled our first Turner well, the Sundquist Flats, we drilled a Parkman well off the same pad. And we’ve done similar tests in the Sussex and Niobrara,” he added.

Another E&P that’s adding rigs is Devon Energy. The company indicated on its second-quarter earnings call that it has plans to pick up a third rig later this year and is likely to add a fourth rig sometime in 2019.

Looking ahead, Devon Energy’s capex plans in the PRB will be focused primarily on the Turner and Niobrara, supplemented by the Parkman, Teapot and other possible zones. In its Super Mario area, the company brought online two Turner wells, with an average IP-30 of 1,450 boe/d (75% oil). In the same area, it said its initial two Niobrara wells were still flowing back.

“We’re starting to define what the development plan will look like. We’re also having some positive results in the Niobrara,” said Devon Energy’s CEO, Tony Vaughn. “In 2019, we expect to be in full development there, with increased activity beyond that. Everything that we’re seeing in the Powder is developing just to plan.”

With the energy sector ramping up its development plans, how big could activity grow in the near term?

One sign of the rate of growth may be judged by the course of an Environmental Impact Statement (EIS) for the Converse County area. Unofficially started in 2014, the EIS was backed by five public E&Ps and included plans for 1,500 wells. However, not surprisingly, the EIS lapsed during the downtown.

Early this year, an outline of the now revived EIS was released, and the EIS now calls for as many as 5,000 wells—in just a portion of the PRB.

Chris Sheehan can be reached at csheehan@hartenergy.com.

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