In 2012, Oklahoma delivered the Scoop-Woodford play. In 2013, the Stack-Meramec. In 2014, the Scoop-Springer. Last year, it produced the overpressured Stack-Meramec. A late-March survey by R.W. Baird & Co. of buysiders, industry members and others placed these just behind the Midland and Delaware basins as favored U.S. oil shale plays.

“Permian [Basin] and Scoop/Springer/Stack are seen increasingly as the only economic [liquids] plays amid this weak pricing backdrop,” reported Dan Katzenberg, E&P analyst for Baird Equity Research. “Affinity for other areas like the Eagle Ford, Bakken and Utica continues to wane.”

In February, the EIA revealed a new estimate of the state’s monthly oil production, beginning with January 2015 and based on a new method of collecting data. Its new projection added 100,000 barrels (bbl) to daily production for a total of some 400,000 at year-end 2015. By its count, the state’s production reached 473,000 bbl/d in March 2015. That rate had not been reached since November 1984.

While strong oil prices preceding 2015 propelled some of the growth, a change in state law in 2011 also has contributed. The state began to allow two-section laterals in unconventional resource formations with its adoption of the Shale Reservoir Development Act. At the time, the state was producing some 200,000 bbl/d.

As the industry is now advocating that the state allow two-section laterals in conventional zones as well, and at the rate operators are testing more stacked pay with at least one-section horizontals, Oklahoma is due for another new play any month now.

Potential horizontal landing zones in the Stack play include the Hoxbar, Oswego, Chester, Meramec, Osage, Woodford and Hunton.

Delineating the Stack

Stack founder Newfield Exploration Co. drilled its horizontal wildcat in the play in 2011 when its Anadarko Basin production was less than 3,000 barrels of oil equivalent per day (boe/d). Its net leasehold across the basin was less than 125,000 acres at the time. It revealed the Stack play in 2013, naming it for “Sooner Trend, Anadarko (Basin), Canadian (and) Kingfisher (counties).”

While it has a position in the Scoop (South-Central Oklahoma Oil Province) play south of Stack as well, its leasehold in the Stack alone today is 225,000 net acres. It averaged 18,866 boe/d of production from the play in 2015, 53% oil and 20% NGLs. The 2015 average was six times that of its 3,178 boe/d from the area in 2013.

Its pre-tax rate of return at $35 WTI, $2.50 gas and a $7 million well cost is between 15% and 20%. And that doesn’t factor for its hedges. “The hedges we treat separately and apart,” said Gary Packer, executive vice president and COO. “We don’t use those to prop up play returns.” And it expects to get its Stack well cost down to $6 million; these would make a nearly 100% pre-tax ROR at $65 WTI, it reported.

Its hedges in this quarter, for example, involve approximately 46,000 bbl/d of oil at between $70 and $96/bbl. In second-quarter 2017, they involve 20,000 bbl/d at between $74 and $95. It realized $500 million in hedge gains in 2015 and estimates $265 million in gains in 2016.

In 2015, it added another 20,000 acres in the overpressured Meramec window in Blaine County to its leasehold, which is primarily in the normal-pressured Canadian and Kingfisher counties, taking the position to the current size. “Most of the large positions have already been captured,” Packer said. “The Felix [Energy Holdings LLC] position Devon [Energy Corp.] acquired was really one of those last large positions available.”

Devon acquired 80,000 net acres in Blaine, Canadian and Kingfisher earlier this year from EnCap Investments LP-backed Felix for $850 million in cash and 23.47 million shares worth $950 million at the time of the announcement on Dec. 7. The position is north of Devon’s existing Anadarko Basin position in the Cana-Woodford play, bringing its total holding in the area to 430,000 net acres.

Devon estimates 10 zones are prospective for laterals in the Felix leasehold, including multiple landings in the Meramec, Osage and Woodford. Its Anadarko Basin position had 5,300 risked locations; the Felix portfolio added 1,400 risked and more than 3,000 unrisked. Felix was producing 9,000 boe/d net, bringing Devon’s to some 80,000 a day in the basin. Devon estimates risked resource is about 400 MMboe.

About 50% of the position Devon acquired is operated by Newfield, Packer said. “It’s something we know quite a bit about.” The deal also gave Newfield and the Street a price on the leasehold’s value: some $20,000 an acre at the time of the deal’s announcement.

“And it’s always great to have another reputable company in there that can work along with us as we drive inefficiencies out of the system. We certainly welcome Devon to the party to help us continue to drive efficiencies,” Packer said.

Newfield’s position is also intermingled with Cimarex Energy Co.’s in some areas. The two operators’ share prices were among only a few E&P stocks to outperform the E&P index EPX in the first quarter. EPX was up 2.76% year to date at March’s end; XEC, up 9.01%; NFX, up 35.68%.

West and northeast

The 20,000 net acres Newfield added last year in Blaine County are west of the original play in Canadian and Kingfisher. There, several Continental Resources Inc. wells along the Blaine-Kingfisher border are adjacent to Newfield’s. “So those wells that they drilled, we have positions in and around them,” Packer said. One of these, Newfield’s Scheffler 1H-9X, had a 30-day initial production (IP) rate of 1,843 boe/d, 77% oil, from a two-section lateral.

Continental’s newest wells in that east-central area of Blaine are Compton 1-2-35XH, which IPed 2,547 boe/d, 71% oil, and Blurton 1-7-6XH, which IPed 2,328 boe/d, 78% oil. Both have two-section laterals.

A Continental stepout, Boden 1-15-10XH, 16 miles southwest into southern Blaine County, came on with 3,508 boe/d, 28% oil. Newfield isn’t near the Boden well currently, Packer said. “It has quite a bit of gas in it and, generally, that’s what happens as you move in the direction of the Boden well.”

Newfield landed 54 new two-section laterals in the Stack last year, producing a 90-day rate on average of 960 boe/d, 61% oil and 79% liquids. The 30-day average, including gas, was 1,122 boe/d, 68% oil and 83% liquids. Its 2016 capex plan is for $510 million in the Anadarko Basin—roughly 80% of its total capex budget—with some $325 million of that devoted to the Stack.

With roughly five rigs at work for it this year, it expects to drill around 80 wells in the Stack and Scoop. Its Stack focus now is on continuing to HBP its position. “Blaine is certainly of interest, but we have time as it relates to HBPing this area,” Packer said.

Going northeast in Kingfisher to where Gastar Exploration Inc. is drilling the Meramec, Newfield has acreage as well “and we like the results we’ve seen. Any time we get some complementary results from another operator, it helps us,” Packer said.

Gastar’s first 100%-operated Meramec well, Deep River 30-1H, came on late last year with a peak 24-hour rate of 1,094 boe, 71% oil, from a 5,100-foot lateral; the 10-day average was 1,042 boe/d. Stimulation stages totaled 34; proppant was 12 million pounds.

Packer said of Deep River, “It would really define our northeastern position and I think that, not only was it an encouraging test for us, it was encouraging to the Street as well.” As most of the Stack-prospective acreage has been captured now, Packer said, “I think the industry is more willing to share information regarding best practices in regard to drilling and completion.”

Newfield expects its leasehold will be 65% HBP by year-end, particularly with two-section laterals where possible. “But there are interesting results coming out of the standard laterals,” Packer said. “They cost about 60% of the longer laterals. I think the jury is still out as to whether the results being enjoyed by those wells are driven by the lateral length or the landing zone and the completion technique.”

Landing, proppant

As for where the laterals are landed in the Meramec, there are several areas in the formation, which is up to 450 feet thick. “We’re working to assess some of these from a recovery standpoint. But, especially in the environment we’re in right now, we’re looking at identifying zones we can drill faster, so that will directly translate to lower costs,” Packer said.

Newfield is also experimenting with greater proppant loading. Historically, it has used some 1,500 pounds per lateral foot. And it is using dissolvable diverters to allow for tighter clusters between 50 and 65 feet apart. “It would be more typical today for Newfield to have eight clusters with 50-foot spacing in concert with the dissolvable plugs,” he said.

Seaport Global Securities LLC analysts reported that Newfield’s wells with tighter cluster spacing and diverters have outperformed the 950 Mboe estimated EUR. They expected the company to test greater proppant this year and added, “Gastar employs 2,400 pounds per foot, and Continental has tested up to 1,800.”

A significant portion of Newfield’s leasehold is in Stack’s western, overpressured window, which begins in western Canadian and southwestern Kingfisher counties. In addition to the Woodford and Meramec, prospective horizons are Osage, Chester, Hunton and Oswego.

Operators that are more HBPed will be ahead of Newfield in terms of development mode, thus identifying spacing and testing additional horizons, Packer said. “We will be rooting them on and, ultimately, will benefit from some of their learnings.”

In density, Newfield has drilled 12 well pairs to date 800 to 1,800 feet apart.

“That’s the extent of the pilots we’ve drilled thus far.” It will watch how other operators’ density tests perform and, by virtue of being nonop in some of them, will gain additional insight.

Meanwhile, other operators will learn from Newfield’s delineation work, Packer said. “We have a number of quality operators in the basin, which I think will only help us challenge each other and collaborate. Considerable improvement is possible in EUR, spacing identification and completion efficiencies.”

Newfield’s market cap has grown in the downturn rather than declined, despite two rounds of equity issuances; its stock price in late March was 6.4% greater than two years earlier. The second equity offering was priced at $23 a share in early March; the stock was trading at $33 in late March.

Packer said the Street “essentially now understands the viability of the play” and has taken notice of the company’s oily exposure in Oklahoma, balance sheet and potential asset sales. “Investors are focusing on basins and assets they believe will deliver growth and returns in this commodity-price cycle.”

Outside of Oklahoma, it holds positions in the Bakken, Eagle Ford, Uinta Basin and offshore China. “Nonstrategic asset sales are definitely something we will pursue this year,” he said. “We may add to our Anadarko Basin position, too.”

Overpressured Stack

Continental Resources surprised the market and industry in 2015, announcing that it was also in the Stack and had a well online already. Harold Hamm, chairman and CEO, said at Oil and Gas Investor’s recent Energy Capital Conference that the company watched the play develop in Canadian and Kingfisher counties in the normal-pressured window.

It became intrigued when considering what the Meramec would do in Blaine County in the overpressured window. “You start looking at everything with a ‘3x’ [production, reserves] on it over there … you start getting enamored with it,” he said.

In Dewey, Custer and Blaine counties, far west of the play’s start, it had legacy acreage held by vertical conventional wells. In Blaine, adjacent to the original Stack play, “is acreage I was drilling Morrow-Springer wells in back in 1992,” Jack Stark, president and COO, said in an interview. “I didn’t even come close to having the vision that an oil and gas field of this magnitude was beneath the Morrow-Springer section. Neither the concept nor the technology were available at that time.”

Boden, the 16-mile southwestern stepout in Blaine County, had a 24-hour IP of 1,000 bbl of oil and 15 MMcf of gas from a 9,800-foot lateral at about 12,550 feet with 5,400 psi of flowing casing pressure. After 82 days online, pressure was more than 5,300 psi on a 20/64-inch choke. Continental deems the stepout area the “overpressured condensate window.”

The company’s first Stack well, Ludwig 1-22-15XH in east-central Blaine, was announced in August with an IP of 1,580 bbl of oil and 3 MMcf of gas per day or 2,076 boe/d, also from a two-section lateral. Pressure in its first week of production was 2,100 psi on a 34/64-inch choke. The oil is 44-degree API; the gas, 1,460 Btu.

Stark said the Street wasn’t expecting that in 2015. It was expecting Continental to demonstrate financial discipline alone and was surprised the company added another play to its portfolio. Cowen and Co. equity analyst Charles Robertson II wrote, “Continental’s first Stack well was Stacktacular at over 2,000 boe/d.”

Continental announced two newer two-section wells near Ludwig in November: Ladd 1-8-5XH and Marks 1-9-4XH. Ladd came on with 2,181 boe/d, 79% oil; Marks, with 994 boe/d, 73% oil. In February, the company demonstrated repeatability in this same area, which it deems the overpressured oil window, with the completion of Compton and Blurton, Stark said.

It has 155,500 net acres in the Stack, 60% HBP, with more than 95% of this in Blaine, Dewey and Custer counties in the overpressured window. Based on its and neighboring operators’ wells, it estimates an EUR of 1.7 MMbbl from 9,800-foot laterals and that a $10 million well would make a 55% rate of return at $40 WTI and $2.25 gas. It expected to drill 25 operated wells in the play this year, complete 15 and have more than 70% of its leasehold HBP by year-end.

Walking west

In the eastern, normal-pressured window where the play began, “other operators were making some nice oil wells,” Stark said. “One-mile wells, then two-mile wells. The play continued to walk from the east to the west. As it got close to our acreage, we started to see results that really caught our attention.”

The overpressured window is where the Meramec is thickest. The Boden well’s 5,400 psi of flowing casing pressure “is extremely strong with that kind of liquids volume.” The Boden, Compton and Blurton “are really some of the best wells I’ve been involved with in my career,” Stark said. His career as a geologist began in 1978.

“Look at the Boden well: It produced 144,000 boe in its first 82 days, 28% oil. It was still flowing around 400 barrels of oil and 6.3 MMcf a day at 5,350 psi at 82 days. It just shows you how strong deliverability of the Meramec is in this overpressured window.” This type of flowing pressure is common in a deep gas well, he added; not one “with this much liquid with it.”

Continental estimates that, based on industrywide results to date, two-section Meramecs completed in the overpressured window will produce three times the hydrocarbons in the first 90 days that two-section Meramecs will produce in the normal-pressured window. “In these resource plays, pressure is your friend.” When might Boden go on lift? Stark said that is unknown but, “clearly, this well will be flowing for a long time.”

Continental used logs from some 500 wells drilled in its leasehold in analyzing the potential for expanding the play westerly. “This whole petroleum system is, essentially, derisked from a geologic standpoint. We know where the Meramec, Osage and Woodford are present. We know what their relative thickness is and where they are best developed in our acreage block.”

Its aim now is to derisk it in terms of what productivity is possible from each reservoir.

An early and leading operator in the Bakken play, Continental sees the stacked pay in its Stack leasehold as benches like the Three Forks intervals underlying the Bakken, Stark said. As a petroleum system, “anywhere you drill a well in this system you will make a well. You will get production. But you want to be in the highest deliverability portions of that petroleum system.”

Boden was landed in the uppermost section of Meramec, which, in Continental’s leasehold, is more than 500 feet thick and appears at about 12,500 feet. “That’s a lot of hydrocarbon column.” It has identified three drilling targets in the Meramec and on average expects two of the three targets to be developed in each drilling and spacing unit. “And there are Osage and Woodford targets as well.”

Its first density test will look at two layers of Meramec and at the Woodford. “Right now, there are other density tests going on [by other operators]. We’re in the early stages of determining what full field development could look like here. We’re contemplating, right now, four wells per zone.”

Walking southeast

Continental currently estimates that 30% of its acreage is in the oil window, 50% to 60% in the condensate window and, the rest, dry gas. In March, it was drilling on the Blaine-Custer line, the farthest southwest test of Meramec to date. It was also drilling due south of Boden.

It is watching Osage development by others over in Dewey County. “They are making very nice wells up there,” Stark said. “The Osage play appears to be walking from the northwest to the southeast toward our acreage. We’re being patient and allowing that to evolve while we focus on the Meramec to the southeast.”

While the Stack was emerging in the normal-pressured window, Continental was working on its Scoop play and watched the early Stack data. Entering the play “went from not being a priority to becoming a very significant asset for the company in about six months,” Stark said. “It’s an amazingly fast evolution and a very significant asset for the company going forward.” The company’s early estimates are that the play could add as much as 25% to its net unrisked resource potential.

Pearce Hammond, managing director and co-head of E&P research for Simmons & Co. International, wrote that Continental’s optimism about its Stack prospects is justified. But, as it continues to delineate the oily limits of the Meramec southwest and west in its leasehold, it will eventually “hit a very gassy well,” which “could set investors up for a temporal disappointment relative to potentially overly ambitious investor expectations.”

He urged investors to understand the nature of delineation “and not set their expectations too high.”

Northeast expansion

Gastar Exploration ended up in the Stack via the Hunton play. “We were looking for a more liquids-weighted play to diversify away from natural gas,” Russ Porter, president and CEO, said. “The Hunton had a high oil cut, low water cut and reasonable drilling costs. Once we got in the area and started looking at other formations, certainly the [overlying] Woodford caught our attention and the Meramec.”

Other operators’ activity started to blossom in the Meramec. “Thankfully, we have it on our acreage also. We found ourselves in the middle of the Stack play,” he said.

Gastar bought out its partner in a trade in 2015. In the deal, it gained 15,700 net acres in Kingfisher and Garfield counties for $42.1 million and 11,000 net nonproducing acres in Blaine and Major counties, bringing its acreage prospective for Meramec to 62,200 net.

In its area, Newfield is immediately southwest. “They are all along our south and southwest borders,” Porter said.

Continental’s Boden well is too far west to translate to Gastar’s potential, but “it probably helps firm up our [pre-existing] Canadian County position because, where we are in Kingfisher County relative to Newfield and Felix [i.e., Devon] is sort of where we are in Canadian relative to Continental’s activity.

“The farther west you go, it gets deeper and gassier. The pressure is higher, which gives you the higher EURs and higher IPs, but also higher costs to drill and complete. I don’t think one is particularly better than the other. We’re generating similar-type returns.”

Its Deep River well, which came on with 1,094 boe, 71% oil, had first-90-day production by late March averaging 713 boe/d, 61% oil. With a cost of $6.4 million, Porter estimated that its EUR of 705 Mboe, 50% oil, at current drilling and completion costs could generate a 44% return, using the March strip.

Deep River in northeastern Kingfisher is the most northeastern Meramec horizontal by a public company in the play. In April, Gastar’s Holiday Road 2-1H well, a farther northeastern stepout, was expected to begin flowback. Like Deep River, it was completed with 34 stimulation stages and approximately 12 million pounds of proppant. However, the 12 million pounds were applied to some 700 fewer feet of lateral.

Holiday Road may be the farthest northeast that Gastar will drill, though, Porter said. “That well, with our Deep River well and all of the surrounding activity by Newfield, PayRock [Energy LLC], Chaparral [Energy Inc.] and Alta Mesa [Holdings LP] really de-risks that entire position up there for Meramec potential.”

It isn’t drilling Hunton any longer. “The economics of the Meramec are superior to the Hunton at this time. But the nice thing is that, when we drill a Meramec well, we hold the deep rights. So, when we drill any of those formations, we hold all formations,” Porter said.

The sequence for the Stack is Oswego, Meramec, Osage, Woodford, Hunton. Gastar has gotten a lot of looks at each in the past when landing horizontals in the Hunton. About 40% of its leasehold is HBP now, mostly by Hunton wells.

Oswego, Osage

After Holiday Road, Gastar will target the Oswego. “The Oswego is shallower, so the wells are less expensive, and they can hold the same 640 acres. One of our goals is to get as much of our acreage HBP as possible,” Porter said.

Oklahoma has designated the Meramec an unconventional formation, so two-section laterals are allowed in it. Currently, two-section laterals are not allowed in the Oswego, a conventional formation. Porter estimates Gastar has nearly 600 net locations for Meramec and Osage wells in its Stack leasehold.

Chesapeake Energy Corp. is also drilling Oswego wells. “They are right in the middle of our acreage with some of their early wells,” Porter said. “In fact, one of their earlier Oswego wells came on with over 2,000 barrels of oil a day and our first Oswego well will be a near offset to it.”

Chesapeake was completing two additional Oswego wells in the first quarter. During the fourth quarter, it completed three Meramecs. Rouce 4-17-10 1H had peak production of 1,260 boe/d, 80% oil, and Wittrock 16-16-9 1H came on with 2,240 boe/d, 67% oil. The third, Stangl 36-16-9 1H, reached 1,480 boe/d, 84% oil, during eight days of flowback. It planned to bring 35 to 45 new wells online in the Stack this year.

Meanwhile, Alta Mesa reported that it completed 10 horizontal Osage wells in the fourth quarter and was continuing delineation of the Osage and Meramec as well as the Oswego and other formations. Five more wells were completed in the first quarter. It also participated in three horizontals as nonop; those targeted the Meramec in addition to Osage.

It has more than 80,000 legacy acres in Kingfisher County, concentrated mainly in four large units, and an average working interest of about 70% in more than 240 wells in multiple zones. Its 2015 investment in the area was $105 million, and it plans three to five rigs this year, targeting the Osage, Meramec and other zones, with a $95 million capex budget for the play. It also expects to spend up to $192 million this year and into early 2017 in a joint-development agreement with private-equity firm Bayou City Energy Management LLC.

Altogether, it had a 70% average working interest in 381 wells and 135 PUDs. Exiting 2015, Stack production averaged some 9,500 boe/d, 76% oil and NGLs, up 60% from a year earlier. For all of 2015, production nearly doubled from 1.7 MMboe to 3.2 MM. Proved reserves more than doubled to 67 MMboe from 28 MM at year-end 2014.

Porter said, “Obviously, in this type of commodity-price environment, people look at a company like Gastar and have concerns about the balance sheet. What I want people to understand is that the quality of our assets should allow us to resolve our balance-sheet issues.”

Gastar was expecting at press time to close its Marcellus-Utica exit, using the proceeds to pay down its bank revolver to what was expected to be a new, lower borrowing base. It also planned to sell some of its Stack position to further delever—some, but not all.

“We have a lot of interest from people who want our entire position because it is 110,000 net acres, and there really is nowhere else to get that kind of position in the play right now,” Porter said. There has also been private-equity interest in investing in the company. “So, while we’re suffering as much as anyone in the current environment, the quality of our assets gives us a very viable path out of this environment.”

Well cost of $3.7 million

PayRock Energy LLC was formed in 2012 to focus on the Midcontinent where its founding partners had extensive experience, said Rick Kirby, president and CEO. “The Sooner Trend was a natural starting place as it has produced over 350 MMbbl of oil from vertical development and was relatively underexplored with modern technologies,” he said.

The interest was initially in landing horizontals in Osage and Hunton, but neighboring operators’ success in the Meramec and Woodford became apparent. PayRock landed one-section laterals in each. Its first Woodford well, Stiles 1407 1-4H, had a 30-day average rate of 712 boe/d, 86% oil, and its first Meramec well, Cerny 1607 1-35MH, averaged 1,211 boe/d, 76% oil.

“Since then, we have set our focus on building an asset that would be highly valuable in the A&D market, and we have accomplished those goals,” Kirby said. It holds some 58,000 net acres, producing roughly 8,700 boe/d with 52% oil and 21% NGLs. It estimates it has nearly 1,000 locations. “We only failed to make one of our goals $100 oil,” he quipped. “It’s a mistake we won’t make in PayRock II.”

The area is “very competitive and chopped up,” he added. “Our land group has built this position—and continues to build where we can. We are buyers until we are sellers. Unfortunately, this play has largely been picked apart and leased. There are some smaller tracts that trickle in, and we will pursue those opportunities when they present themselves; otherwise, there’s just not much left.”

Meanwhile, PayRock is working to HBP what it has amassed. In March, it was drilling its 32nd well. With one rig at a pace of two wells per month, Kirby expected it will have 50 wells online by year-end and 85% of its core operated position HBP.

In addition to the Meramec and Woodford, the PayRock group sees significant upside from the Hoxbar, Oswego, Osage and Hunton. For now, however, “we’ll continue to stick to the Meramec and Woodford and monitor for other plays to develop that we could potentially pursue on our acreage.”

In mid-2015, the company was looking at where the next PayRock might lease. It looked at the Permian Basin, of course, as well as at other basins. “We’re always pleasantly surprised at how attractive economics are in the Stack relative to these other opportunities,” he said.

“We have yet to find data that suggest there is anywhere else in the Lower 48 that can compete with the economics of the wells we have drilled. There are certainly areas that post eye-catching IPs but, when you consider the costs of some of these other areas, the economics get challenged.”

Its all-in well cost is $3.7 million, and it has tightened cluster spacing to 27 feet. Proppant concentration is some 2,600 pounds per lateral foot, and it is using biodegradable diver­ters. “Using this strategy, we’ve turned on some of our best results, including our best Meramec well.” That one, Stiles 1407 2-4MH, averaged 1,637 boe/d, 82% oil, in its first 30 days online.

At its current well cost and results, it is expecting rates of return of between 45% and 65% at $35 WTI. “We don’t like turning on wells at today’s low prices, but we’re spending capital to economically HBP acreage that will be even more valuable if prices continue to recover,” Kirby said.

One-section laterals

Brandon Mikael, at the time an analyst with Wood Mackenzie, told members of the ADAM-Houston M&A group in 2015 that EnCap’s investments in both Felix and PayRock represented an interesting strategy. “They’re in the same counties, competing heads up with totally divergent strategies,” Mikael said.

“The PayRock team is very focused on returns, so they believe shorter laterals are the optimal way to develop the Stack, whereas the Felix team is looking at two-mile laterals, saying, ‘We need to capture reserves and this will create the most long-term value.’”

Kirby said the reason for PayRock making one-section laterals exclusively is because “we observed early that the second mile of lateral wasn’t adding enough production to justify the costs. While that flies in the face of every other play in the U.S., we have collected significant amounts of data to clearly support this claim.”

The data include details on about 80% of the Meramec wells in the play to date. “Each basin and each play is different. The Meramec is different. The industry hasn’t figured out what’s causing this phenomenon yet but, the way we see it, there are two potential outcomes.”

One is that operators will figure out what is holding back two-section wells’ performance and will fix this; the other, operators will determine the cause and won’t be able to fix it, thus the industry will conform to one-section laterals. “Either way, the news you’ve been hearing predominantly from two-mile development and the associated value gets much better. If you like Stack based on what you’re seeing from investor presentations to date, you’re going to love this play as it continues to unfold.”

As for the play’s westward extension into the overpressured Meramec, Kirby said that, “from the data we’ve collected, we agree that, if you want flashy IPs, chasing the deeper, overpressured reservoir makes sense.” But the wells cost 50% more than those in the shallower, normal-pressured window where PayRock operates, he said. “We haven’t seen consistent results to support that the deeper, overpressured-reservoir results make better economics for the incremental costs.”

For example, he said, PayRock’s farthest eastern Meramec well, Eve 1506 1-20MH, had a 30-day average of 1,003 boe/d, 91% oil. “At our current well-cost estimate of $3.7 million, this well is calculating a 286% ROR at today’s [March] prices. We believe economics will prove to be as good in the east—if not better—as they are in the west.”

‘Pleasantly surprised’

The Stack play is still in its early days with a lot to look forward to, according to Wade Hutchings, Marathon Oil Corp. regional vice president for Midcontinent assets. “With every well we operate and every well other industry participants drill, our understanding of the Stack and its liquid phases improves,” he said. “We are learning more every day.”

The company celebrated its 100th year of operating in Oklahoma in 2015 and holds legacy acreage in both the Stack and Scoop plays, to which it has added via leasing and acquiring small packages.

In 2015, it augmented its position with some 12,000 net acres prospective for the Meramec in Blaine County, building upon existing positions in Canadian and Kingfisher counties.

“Earlier, our assumption was that much of the Blaine County area was going to be leaner, higher in natural gas content,” Hutchings said. “We have been pleasantly surprised; the liquids-rich windows are pushing deeper into the basin than we thought they would. We see the play expanding west.”

Two-thirds of its 2016 drilling budget for the state is devoted to its Stack-Meramec potential. The emphasis will be on delineation and optimizing stimulation and flowback, Hutchings said.

Its early Meramec wells were one-section laterals; plans for this year are for both one- and two-section laterals. Longer laterals are a better value, the company has decided, where it has contiguous sections.

Toward that end, Marathon has been doing some leasing as well as occasionally trading sections with other operators to allow for more extended laterals. It expects that some 70% of its Stack position will be HBP by year-end. “We’re confident we’ll be able to hold our key acreage,” he said.

After the Meramec, Hutchings believes, the Woodford in the Stack is promising, but the Meramec is the priority currently. “We’ve monitored wells that have been drilled in other zones with new stimulation techniques and it looks like there is more upside in the Stack. For us today, however, none of it is as compelling as the Meramec.”

Newfield’s Packer concluded that “not only does [Stack] have incredible economics, it has scale. Where can we see 2 billion barrels of net unrisked resource and more than 6,000 gross potential locations? It’s going to drive Newfield and our results for decades to come.”

Well costs will continue to decline, Packer added. “If we just look back to 2014, we’ve already driven 30% of our well costs out of the system due to efficiency gains and market-based pricing.

“As I sit here today, where we have well costs of $7.4 million, I feel very comfortable that, as we transition into development, we’re going to be looking at some $6 million wells and roughly 2 billion boe of resource. These generate returns very competitive with any other play active in the U.S., inclusive of the Permian.”

Its focus now is on preserving liquidity, holding its Stack acreage and finding ways to improve margins. In 2015, it reduced its lease operating expense on a per-boe basis by 25% and drove G&A down 25%. It expects to drive both figures down another 15% this year, while growing Lower 48 production some 20% and at 50% less cost than in 2015. Packer said, “We are not going to take our foot off the gas in regard to the improvement.”

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