The great western anthem “Home on the Range,” where the deer and the antelope play, promises skies that are not cloudy all day. But on a late August day in Wyoming’s Powder River Basin, they were. All day. Wyoming averages just 10 inches of rain a year and is considered semi-arid, but on this particular day, as we sought out an emerging oil play, the Cowboy State received at least a third of its annual quota.

Nevertheless, the pronghorn antelope were out in abundance, enjoying the persistent precipitation on the high plains, as we cut through a wash and up the hill to RKI Exploration & Production’s Dilts Ranch State 38-71-16-1PH well in Converse County.

RKI is headquartered in Oklahoma City, but the privately held explorer was an early mover in the Powder River Basin unconventional drilling movement, and is currently the most active producer in the play with five rigs running. One of those rigs topped the ridge ahead. The brand new True Rig 37, a National Oilwell Varco rig on its inaugural well, had spudded the day before and was drilling at 1,700 feet on its way to the Parkman Formation, one of a host of stacked oil-bearing formations being targeted by operators across the basin.

The Powder River Basin encompasses 21,000 square miles, but 28 drilling rigs are concentrated primarily in two Wyoming counties. A plethora of stacked formations are prospective across the basin, but most are sandstones that "come and go."

“It’s just amazing what’s happened in a little over a year,” said Tim Haddican, RKI vice president of operations and engineering. “This is all very good crude oil, 39 to 41 API with no H2S [sour gas]. From an operations standpoint, it’s one of the best fields I’ve ever seen.”

Tim Haddican, RKI vice president of operations and engineering, said industry's progress over the past year in the Powder is "just amazing. From an operations standpoint, it's one of the best fields I've ever seen."

Other operators are also pursuing the Powder River's oily potential. EOG Resources Inc., with a portfolio overflowing with marquee resource plays, spotlighted the Powder River as a new core focus in conference calls this year. SM Energy Co., too, is stockpiling acreage and adding rigs. Anadarko Petroleum Corp. is quietly testing a 350,000-acre position. And Chesapeake Energy Corp., currently divesting noncore assets in its portfolio, has emphasized the Powder as a pillar of its oil growth profile. Numerous private companies as well—Samson Resources, Anschutz, Helis Oil & Gas, to name a few—are actively investing in this region of Wyoming.

Since 2009, nearly 600 oil wells have been drilled in the Powder River Basin, which covers 21,000 square miles in Wyoming and Montana. Most of those wells are in Wyoming’s Campbell and Converse counties, according to the U.S. Energy Information Administration (EIA).

“The Powder River Basin is experiencing a turnaround in oil production,” the EIA said in a September report. “Production has rebounded from a low of 38,000 bbl/d in 2009 to 78,000 bbl/d during first-quarter 2014.”

Wyoming geologist Jimmy Goolsby identifies a host of hydrocarbon-bearing zones across the Powder River, but believes the price of oil will determine its economic longevity.

And if momentum is an indicator, production is on the verge of ballooning.

“When we look at the potential—more than 2 billion barrels of gross recoverable resources just on our acreage—it’s a massive basin with multiple stacked resource opportunities,” said Chris Doyle, Chesapeake senior vice president of its northern division.

Operators in the Powder like what they see.

Rock talk

The overpressured portion of the Powder River Basin encompasses some 4.8 million acres along a diagonal axis extending 150 miles southeast to northwest and 50 miles east to west. The multiple hydrocarbon-bearing zones of the Powder River are primarily dirty sands, according to Wyoming geologist Jimmy Goolsby. These were laid down over a 50-million-year period when a sea stretched across the region. Thus, the formations are not consistent, a result of sandstones deposited over time at varying depths. Not all zones are prospective across the basin.

Following years of decline, production in the Powder River Basin has doubled in five years, according to the EIA, and is continuing its upward trend.

“They come and go,” said Goolsby, managing partner of Goolsby, Finley and Associates in Casper. “Ninety percent of what we’re drilling today is not shale plays, but the sands and silts of the Cretaceous Interior Seaway, which was either overlying the area or moving back and forth over it through time.”

He sees challenges in identifying commercially producible areas, “but these sands definitely have sweet spots. It’s not a cookie-cutter play—you’ve got to understand the geology to be successful.”

It is these multiple layers through thousands of feet of depth, however, that are alluring to operators bearing new technology developed in shale plays to extract the hydrocarbons. Goolsby identifies the commercially producible sand zones: the Frontier and Turner, the deepest zones, which are related and sometimes intermingled; and the Shannon, Sussex, Parkman and Teapot.

“Right now I’d lean toward the Frontier-Turner as the more highly prospective” because it is overpressured, “but I don’t know if that will hold,” he said. The Parkman and Teapot, much shallower but underpressured, are significantly cheaper to drill.

The Powder River extension of the Niobrara Shale from the D-J Basin to the south also shows good economics, but mostly in the southern region of the basin. Moving northward, the shale exhibits more clay content, making it less permeable and brittle. “That’s why we’re not seeing as much Niobrara production away from the southeastern part of the Powder River Basin,” he said.

Goolsby sees potential in the Dakota and Muddy sands and the Mowry Shale as well. The Mowry, in particular, has thwarted operators in the past. In situ bentonites create an effective frack barrier within the rock, he explained. “You may be able to frack across the bentonites, but you’ve got to be careful what you put into [the completion], or it’ll close.”

Ultimately, the price of oil will determine the longevity of the Powder, he believes. “It’s sensitive to price. The Powder River will remain strong if prices hold, but you’ve got to have $70 or $80 [WTI] to make this profitable.”

Irani's opus

RKI Exploration CEO Ronnie Irani led the charge to open the Powder River to unconventional development. "The economics are fantastic. These are the types of returns companies gravitate toward fast."

Wyoming is the least populous state of the union, with vast expanses of rolling plains. The rain blurred the windshield as we turned west off Highway 59 and followed an unpaved ranch road in central Converse County, the horizon extending far ahead. “How far west before crossing another paved road?” I asked RKI’s Haddican, who was driving. “About 20 miles, maybe 30,” he said. RKI has three of its five Powder River rigs nestled within the gentle hills of this ranch, drilling the Parkman sands.

RKI got its foothold in the Powder River in 2006 when namesake Ronnie K. Irani returned for an unconventional encore. A veteran of gas producer Dominion Resources, in his earlier career Irani worked the conventional Powder River with Woods Petroleum Corp. And while all the large independents were plying gas resource plays when he left Dominion, Irani remembered the Powder’s potential.

“In the Woods days when targeting Dakota, when we drilled through the Niobrara, we’d get production out of it and formations above it, in spite of not paying attention to it,” he said. “When I mapped the Niobrara inside the Powder River, it was substantial. It was so large I was amazed none of the big boys were in the basin.”

But the opportunity was too large for him to handle independently. He approached his Oklahoma City neighbor Chesapeake Energy, then a chiefly gas producer, and convinced Chesapeake to buy in to the oil-weighted prospect. The 50-50 undivided partnership stipulated Chesapeake to operate all formations from the Niobrara and deeper, and RKI to operate shallower zones. The two quickly built a 900,000-acre position in the heart of the basin. “We had to move fast or the acreage would go away.”

Subsequently, Chesapeake proceeded to drill 160 Niobrara wells in the southern basin in which RKI partnered, bringing in Chinese national oil company CNOOC along the way for a third of its 50% interest. RKI still paid 50% as a nonoperator.

Although most of RKI’s annual $300- to $400 million Powder River budget was plowed into Chesapeake’s Niobrara drilling machine, two years back the company decided it needed to derisk the northern acreage, away from Chesapeake’s activity. Since that time it has ramped from no rigs to five and drilled 60 operated wells targeting the Parkman and Teapot sand zones above the Niobrara as per the agreement. Chesapeake and CNOOC remained as nonoperated partners.

The good news about shallow drilling is it’s fast and cheap. “The economics are fantastic!” Irani exclaimed. At $5- to $6 million, rates of return range from 70% to 90%. “I would put that against any play,” he said. “These are the types of returns companies gravitate toward fast.”

And there’s upside. Already these wells are being drilled in 10 to 12 days but, “Once we get on pad drilling, we see that cost coming down substantially.”

Irani puts estimated ultimate recovery (EUR) for the Parkman at 500,000 barrels of oil equivalent (boe) per well, and 350,000 for the Teapot. “The Parkman is No. 1 for us, and the Teapot is great too.”

All RKI laterals are between 4,000 and 4,400 feet, Irani said, largely due to a comfort zone on 640-acre units. “There is room to improve the economics by looking at longer laterals.”

This summer RKI and Chesapeake agreed to divvy the spoils and part ways so as to have higher working interests in operated wells. Chesapeake kept the southern acreage where it was most active, and RKI took the northern, with 360,000 net acres at 83% working interest. CNOOC remains a 17% partner in both.

The swap means RKI now owns rights to all depths and controls its program, which is a conundrum in and of itself: what gets capex first?

“We have identified over 10,000 locations within different zones on our acreage,” he said—2,000 in the Parkman and Teapot—and he thinks eight prospective zones are present across at least 80% of RKI’s holdings. “Our acreage is on a sweet spot, which was intentional, because we were able to map it before industry moved in.”

One rig is dedicated to Niobrara drilling, and the company plans a Frontier/Turner drilling program in the fourth quarter, following the path of EOG, Devon, SM Energy and others. Haddican noted these were the primary plays when the company raised funds ahead of the Chesapeake partnership that gave those zones to the larger operator. RKI also plans a Sussex well in 2015.

“I think the Frontier is our next zone to develop,” Haddican said.

Of the deeper zones, Irani likes the Dakota, Muddy and Mowry for future upside.

As of the end of August, RKI was producing 6,100 boe/d from the Powder River. Free to operate, it will add another three rigs over the next couple of years to reach eight, he said, and the company expects to drill another 107 wells in 2015. “We’ve got a lot of room in the Powder to grow.”

After cashing out in the Eagle Ford, Meritage Midstream targeted the Powder River Basin as its next best opportunity. "We see plenty of drilling inventory, which we expect to continue for at least a decade," said Meritage president Nick Thomas.

When EOG speaks

Perhaps the benchmark operator for assessing unconventional plays, EOG Resources, in its first-quarter conference call, put its esteemed stamp of approval on the sleeper Powder River with a final investment decision for the Parkman and Turner formations, and three other exploratory plays. The announcement turned Wall Street heads. In a chart ranking returns within its portfolio, EOG places the Parkman at fourth behind its Eagle Ford, Bakken/Three Forks and Delaware Basin Leonard shales, and the Turner at sixth following the D-J Basin Codell—all above 100% returns.

“We’ve set a high threshold at EOG with plays like the Eagle Ford, Bakken and Leonard, and other plays that compete for capital require the same rate of return metrics,” EOG CEO Bill Thomas said in the call. “The plays we’ve announced today are certainly in that category.”

EOG holds 30,000 acres prospective for the Parkman. It drilled 10 wells in 2013, with 28 more planned this year. Well laterals average 7,300 feet, yielding in excess of 1,000 boe/d (69% oil) and EUR of 850,000 boe per well. “At $5 million per well, direct after-tax returns exceed 100%,” Thomas said, “making the Parkman the highest rate of return play” of the four plays announced.

He estimates net potential reserves for the Parkman at 75 MMboe, with 115 net drilling locations.

EOG revealed that the Turner Formation is prospective on 63,000 net acres, overlapping the Parkman program to some extent. The company drilled eight wells in 2013 to the Turner, with two published well results around 700 barrels and 1.1 MMcf of gas (34% oil; 23% NGLs), and plans six this year. Laterals vary from 4,600 to 9,000 feet, with EURs near 860,000 boe at the higher end. These wells cost $7.5 million. EOG anticipates potential reserves of 115 million barrels at this juncture, with 160 net locations.

SM Energy president and COO Jay Ottoson immediately deployed Bakken-esque laterals and completions into SM's Powder River Frontier drilling program with "solid returns."

The fighting Frontiersmen

SM Energy Co. has rationalized its portfolio over the past three years, divesting out of certain areas and coring up in others, like the Bakken/Three Forks and Eagle Ford. The Powder River is becoming one of its anchors.

“We look for plays that have high margins and a lot of drilling inventory,” said Jay Ottoson, SM Energy president and COO. “If you look at the Powder, we saw geologic potential and the opportunity to build a large position at relatively low cost.” And with six horizontal wells on sales at the end of the second quarter, the results are “pretty encouraging,” he said.

In May 2013, Denver-based SM committed to the Powder with a 40,000-acre purchase from QEP Resources Inc. at approximately $1,500 per acre, and has made bolt-on acquisitions since. It presently holds 166,000 total Powder River Basin net acres across northwestern Converse and into Campbell and Johnson counties with 127,000 net acres prospective for the Frontier and Shannon formations, its two primary targets. Since then, SM has drilled and completed five horizontal Frontier wells and participated in another 11. It also has a completion in the Shannon.

Ottoson considers a 30,000-acre block on the north end of the position derisked. “The rest we’re still delineating, and should pick up quite a bit of data in the next six months.”

Although at the very front end of its drilling program here, Ottoson is stoked about the potential. The operated Loco [Johnson County] and Rush [Converse County] wells are in the northern realm of its acreage.

“The Loco is a terrific well,” producing 1,400 boe/d at a 30-day peak rate, he said. “The Rush, on a per-lateral-foot basis, is the best well we’ve drilled. It only has a 3,800-foot lateral—drilled to hold acreage—and that well IP’d at almost 750 boe per day.”

To the south, in Converse County, the Blackjack and Dandy wells—with laterals approaching 10,000 feet—flowed more than 900 barrels daily on 30-day rates at 75% to 80% oil. “These wells are going to be 800,000 to 1 million barrels equivalent reserves and are highly economic.”

Whether genius or serendipitous, SM wasted no time in maxing out completions to quickly achieve these results.

“We basically took our Bakken program and said, ‘Let’s try to do that on the Frontier.’ We drilled long laterals and pumped a similar completion to our Bakken completions, except we’re using more high-strength proppants because it’s deeper, with higher stresses.”

The massive stimulations come at a price, however. Currently, the drill and completion cost is $16 million per well. Ottoson emphasizes that even at this cost, well economics exceed the company’s internal hurdle rate of return of 25%.

“We are generating solid returns on these early wells. These are very oily wells with a lot of revenue up front. When we get well costs down to $14 million and optimize our completions, these wells will be very competitive with the rest of our portfolio.”

SM started the year with one rig and will be at four by year-end with another expected to join by mid-2015, paced somewhat by permitting. It will spend $170 million in 2014, which is 10% of drilling and completion capex. Next year he foresees drilling 20 to 25 wells, essentially doubling activity in the Powder River.

Since the QEP acquisition, acreage now trades at three times that price or more, he said. “People are more focused on the play. It’s oily and EOG talking about it gets a lot of people excited.”

In 2015, SM plans to run five rigs in the Eagle Ford and a similar number of rigs in the Bakken/Three Forks. “From a rig standpoint, our Powder River Basin program is going to be as big as any other we’re running next year. It’s going to be a material part of our business.”

Exciting basin to play

Anadarko Petroleum Corp. is another large operator playing the Powder. Yet Anadarko remains mum about its operations, scarcely mentioning the Powder in its second-quarter earnings call but noting “very encouraging results.”

Nevertheless, the company sports a 350,000-net-acre position across four areas of the region. In its first-quarter conference call, Anadarko’s executive vice president of U.S. onshore E&P, Chuck Meloy, pointed to the southeast region as the most exciting, where the company is targeting Niobrara, but also noted Shannon and Frontier programs as showing “early promise.”

“The basin is an exciting basin to play because it has a big oil column, fully saturated, with a lot of different intervals to work … It’s another opportunity to add a big oil play into our portfolio.”

The company dropped from three operated rigs in 2013 to one in 2014, but noted it is shifting to pad drilling. At the end of the second quarter, Anadarko reported 2,000 bbl/d and 225 MMcf/d from 32 operated, producing wells. It invested $50 million into the Powder River during the quarter.

Second time charmed

At one point in 2012, Chesapeake was running 11 rigs in the Powder River Niobrara play, but dropped to three when new management took over last year. A companywide portfolio housecleaning ensued. Could the Powder River make Chesapeake’s cut?

“The Powder River Basin is a world-classasset,” affirmed Chesapeake’s Chris Doyle.


“It’s oily and offers plenty of running room—upward of 1,800 potential locations in one footprint.”


An 18-year veteran of Anadarko Petroleum, Doyle last summer was recruited by new Chesapeake CEO Doug Lawler, also from Anadarko, whose focus is on value creation more than held-by-production drilling. When he arrived, Doyle said the Powder River program was rife with inefficiency and destined to be abandoned.

“A year ago, without the drilling carry [from partner CNOOC], we were losing money, below 10% returns for sure. Those rigs would have gone away,” he said. Yet the geology was never in question. “We’re very, very happy with the EURs,” he said. “The subsurface has never been the question, honestly.”

The former regime was drilling harder, not smarter, he said, and not paying attention to returns.

“They were running the wheels off these rigs and were unable to focus on what would truly unlock this play.” While geologists would identify the best rock in the Niobrara Formation, and the drillers would attack it the best they could, it tended to be naturally fractured, resulting in millions of dollars of mud losses and drilling problems. Yet the so-called recipe did not change. Wells took 40 days to drill and costs topped $12 million. “We just couldn’t make money at that cost.”

A companywide organizational change centered business units around a common goal—to unlock value. Drilling engineers worked with geologists to change the target window by 15 feet into less fractured rock, among other issues.

Now, nonproductive time has significantly decreased, Doyle said. Wells are being drilled in less than 20 days, with longer laterals and enhanced completions, for $8.5 million. Rate of return is 40%.

“There has been a substantial transformation in how our team is unlocking the value of this asset. Seeing the drilling team work with the geologists to better understand this area has knocked out a ton of nonproductive time. We will actually be able to unlock this play running three rigs a lot faster than we would with 10, because it will give us the time to rethink essentially everything we were doing in the play.”

Chesapeake has mobilized a fourth rig to the play, and could go to nine by year-end 2015.

“Seven to nine rigs in 2015 will essentially be as effective as 20 rigs last year, just in terms of cycle times and efficiencies. By slowing down and figuring it out, we’ll be twice as efficient when we ramp back up.”

Following the working interest swap with RKI, Chesapeake now holds some 388,000 net acres in southern Converse County with an average 79% working interest. Peak Niobrara IP rates average 1,740 boe/d. Current Powder River production is approximately 14,500 boe/d.

About 50% of Chesapeake’s Powder River Basin stream is oil, with NGLs approximately 35% and dry gas comprising 15% of the current production mix. Doyle inherited some 50 wells shut in due to lack of processing infrastructure. That bottleneck will be alleviated, at least for awhile, with the commissioning of Access Midstream’s Buckinghorse gas processing facility in November, with capacity of 120 MMcf/d. “That’s a big catalyst for the ramp-up,” Doyle said.

Slowing down to understand its program resulted in Chesapeake Energy's Powder River returns jumping from 10% to 40%, said Chris Doyle, senior vice president of the northern division.

While the Niobrara is the “base load” for Chesapeake’s Powder River program, present across its entire acreage position, Doyle has his eye on other Upper Cretaceous oil-bearing formations, including the Sussex, Parkman, Shannon and Teapot. These are shallower and easier to drill, he noted. While not blanketed across the acreage, “they are significant,” he said. Chesapeake plans to deploy more rigs into these oily zones shortly.

The company now has three Sussex tests online, and “well results have been outstanding,” he said. The first, online for six months now, still makes more than 1,000 bbl/d, “not equivalent,” he said, “just some phenomenal well results.” He anticipates returns in excess of 50% here, and plans to dedicate two future rigs to the program.

Chesapeake has tested the Parkman with one well, which also had an IP of more than 1,100 bbl/d, 85% oil, with Shannon and Teapot tests coming. The Frontier sands and Mowry Shale remain upside.

“The Parkman looks really good. We’ll continue to feed that conveyer belt as we ramp up,” he said.

Presently, the Powder River Basin represents just 5% of Chesapeake’s capex, but that is destined to change in 2015.

“We’re still very early in our development,” Doyle said, “but the Powder has the potential to be a core asset for the company. This is yet another oil growth engine for us.”

Powder River's expanding midstream

After exiting Meritage Midstream Services I in the Eagle Ford Shale to Howard Energy Partners, the same team, backed by Riverstone Holdings with a $500 million commitment, reformed in 2012 as Meritage Midstream Services II in Wyoming’s Powder River Basin. The comparison bodes well for the Powder.

“We had an early look into some results that were very exciting,” said Meritage president Nick Thomas. “Right away, we recognized there was quite an extensive area that had multi-stacked pay zone potential. We’re still early, but there have been great results across a number of formations, upward of eight to 10. We see a lot of activity in all of those horizons.”

Constrained gas processing and crude takeaway capacity are factors in the Powder River Basin’s slow emergence, but Meritage is developing solutions for both, as well as water gathering.

With Wyoming’s tight regulations on flaring, the company first acquired Thunder Creek Gas Services, a coalbed-methane gas gathering system that was in decline, and immediately constructed two gas processing facilities to handle the rich gas produced in association with the new unconventional oil streams. With the second coming online in September, the facilities add capacity in excess of 100 MMcf/d, with an additional 70 million expected by 2015. Thomas projects adding an additional 200 MMcf/d capacity over the next five years.

In addition to the 500 miles of gas gathering lines acquired, Meritage has already laid another 200 miles with an additional 100 miles slated for completion by the end of the year. “We will have tied in approximately 110 wells in 2014 alone. We’ve been very active, and that’s something the basin hasn’t seen for quite a while.”

As a result, the company is now producing some 2,000 bbl/d of NGL also, currently trucked to third-party pipelines. “We see that number ramping significantly,” he said. “The volumes are going to be substantial.” To that end, Meritage plans a 40,000 bbl/d NGL pipeline expected by year-end 2015. “I can see this basin needing as much as 80,000 bbl/d of NGL takeaway,” he said.

On the crude front, Meritage partnered with Arch Coal to create a crude-loading facility on the coal producer’s existing rail network. The test project, at Arch’s Black Thunder mine in Wright, Wyoming, is capable of loading 15,000 bbl/d, trucked from around the basin. It currently receives about 5,000 bbl/d. Since May, the company has shipped five 70-car unit trains with about 78,000 barrels of oil.

Next, Meritage plans to upgrade Black Thunder with a permanent and efficient loading facility that can handle 25,000 bbl/d with 100,000 barrels of storage capacity. “This is an intermediate step toward having a facility that will run from 60,000 to 120,000 barrels a day through it. By next April, we’ll be able to move a unit train through there about every 48 hours.”

An 80-mile crude gathering pipeline system capable of 50,000 bbl/d, operational by mid-2015, will help feed the facility, and will also be tied into the interstate pipeline system. The takeaway options are designed to be able to tap various regional markets.

“That’s a nice price arbitrage that hasn’t always been accessible to the producing community here,” he said. “They have the opportunity to get the best netback possible.”

Thomas said the midstream is now caught up with producers, with a plan to create capacity just ahead of need.

“We see plenty of drilling inventory out here, which we expect to continue for at least the next decade. Leading indicators such as rig count, permits and capital programs are bullish on development activities here. It looks like the resource is continuing to unfold in very positive ways.”

Power to the Parkman

Devon Energy is also mobilizing. In southwestern Campbell County, Devon holds some 150,000 net acres on which it has identified 1,000 drillable locations, 750 of which lie in the Parkman zone.

“We see these as high rate of return opportunities,” said Devon COO Dave Hager, speaking at a UBS investor event in September. “We’re moving now to focus on a core area where we’ll go into full development.”

To do so, Devon plans a fourth rig by year-end to increase the pace and might further accelerate the program in 2015.

“As we do that, we think we’ll be able to increase IPs and EURs, come up with more enhanced completion designs, drive down costs, and drive up returns of this whole capital program.”

Two second-quarter Parkman wells had average IPs of 950 boe/d [30 days]. Parkman wells cost $5 million with EURs of 250,000 barrels, 95% oil.

Additionally, Hager noted some areas prospective for the Turner Formation were ready for development. “It’s not as material as the Parkman, but there are some areas where we are generating strong economics and that will be part of our overall development program.” He identified 250 drill sites.

Frontier economics are not as strong, he said, because well costs are higher. “It’s a bit longer term,” he said. “We have to put a focused effort on getting costs down before we put a lot into the Frontier.” But, he added, “just like at Cana [Oklahoma Woodford], when we have time to do good technical work, we’ll figure it out.”

Ready to roll

Wold Oil Properties LLC is a 60-year-old family-owned Wyoming producer with a long history in the Powder River Basin. Its affiliate, Wold Energy Partners, was launched in December 2013 as a carve-out of the family holdings, partially backed by institutional investors, and prospective for horizontal development. In the past year, the company has accumulated 75,000 net acres total, with 50,000 prospective for the Frontier Formation, in northwestern Converse and southern Campbell counties.

“The Powder River Basin is a prolific basin providing the stacked-pay potential that you see in other world-class plays. We believe it’s in the early innings,” said Court Wold, finance and planning manager for Wold Energy.

Court Wold, finance and planning manager for Wold Energy, with a long family history in the basin, says the Powder River "is a prolific basin providing stacked-pay potential that you see in other world-class plays."

While building its position, Wold has partnered in wells operated by SM Energy, Anadarko Petroleum, Helis Oil & Gas, Samson Resources and Peak Energy, with exposure to the Frontier, Turner, Sussex, Shannon and Parkman formations. After participating in a variety of wells, “We decided to plant our stakes in the overpressured window of the Frontier-Turner play,” he said.

Historic vertical wells played a part in this decision, where the most robust have come from the Frontier sands, Wold noted. “A number of verticals produced in excess of 1 million barrels. By exploiting that same rock with horizontals, with EURs in excess of 800,000 barrels oil equivalent”—a number he believes is conservative—“we think the reservoir characteristics and the economics are superior in the Frontier.”

Wold Energy has participated in four Frontier wells in 2014 with IPs greater than 1,000 bbl/d. Its most recent well flowed at 1,300 barrels on a 30-day rate, 80% oil. Well costs have trended down to near $15 million currently, with laterals approaching 10,000 feet, yielding internal rates of returns north of 50%. “We see no reason why well costs shouldn’t come down to the $12- to $13 million range similar to Bakken long laterals,” he said.

The private operator has participated in 12 nonoperated wells in 2014 in four separate formations through September, and anticipates another 10 wells by year-end. But with 80 permits in the queue, Wold intends to move into the operator seat in 2015 with its first rig. “We aren’t in this with a nonop model,” he said.

The primary target will be the first bench of the Frontier, but Wold identifies five separate zones within the Frontier, though not homogenous. “Those vary across our position, but each of them is a potential independent target for horizontal development.”

Further upside includes the overpressured Shannon, which has produced “fairly good results” in partnered wells, and the Sussex, in which “results have gotten better” following early challenges. Additionally, “we think the Niobrara will be developed in our acreage block, and we’ve also got prolific Parkman and Muddy production.”

The Dakota and Lakota systems are deeper gas zones that have produced a tremendous amount of conventional gas over the years, he said, and might also be developed horizontally.

Wold expects “to add to its inventory of 150-plus Frontier drilling locations,” excluding the aforementioned zones, all of which exhibit legacy conventional production. Much of Wold Energy’s budget has been directed to acquisitions over its first year, the most recent being its purchase of a portion of Bill Barrett’s acreage and production.

“We’ve got a successful acquisition program right now and we’re going to continue to make deals as long as they make sense, but our budget is shifting to development with more emphasis on operated drilling,” said Jarred Kubat, land manager for Wold Energy.

What’s Wold’s future in the Powder? “We’ve been here 60 years, and I wouldn’t be surprised if we’re out here for another 60 years,” Wold said.

With 75,000 net acres prospective for the Frontier Formation and growing Wold Energy landman Jarred Kubat said, "We're going to continue to make deals as long as they make sense."

Looking ahead

Late in the afternoon in eastern Converse County, down a long muddy road on RKI’s two-well Split Hill 36 frack site targeting Teapot, the sun attempts to break through the dense clouds, but is only temporarily successful. RKI just recently stepped out to the east, and these Teapot wells improve as they go.

“It’s been a pleasant surprise—unexpected,” said Haddican. “I would not have anticipated Parkman or Teapot doing this well when we started.” Each zone has had IPs between 800 and 1,500 boe/d.

An R.W. Baird survey of industry and investors in early October identified the Powder River Basin as the most highly anticipated emerging play. Haddican shares the sentiment.

“The oil in place is tremendous.”

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