LOWER 48 EXPLORATION: ALPINE HIGH

In a 2006 paper, Denver-based consulting firm The Discovery Group Inc. reported that the Barnett Shale potential of the southern Delaware Basin may contain 800 trillion cubic feet (Tcf) of gas across a 12,000-square-mile area. Bob Cluff, the firm’s late founder, said that “Reeves County is the gas-in-place sweet spot.”

At the time, at least a dozen operators were examining the Barnett and underlying Woodford Shale’s potential in the heat of horizontal Barnett success in the Fort Worth Basin. Soon, many turned their capex to other promising unconventional-resource plays, however: the Bakken, Marcellus, Haynesville and Eagle Ford.

Cluff concluded about the Delaware tar­gets, “Whether this shale can actually deliver gas at commercial rates remains to be seen… [It] will take at least 50 wells before indus­try knows if it can deliver like the Fort Worth Basin’s Barnett.”

The play resurfaced in early September with Apache Corp.’s announcement that it had zeroed in on the sweet spot, calling it “Alpine High,” and that it has a plan for monetizing it. John Christmann, CEO and president of Apache, told Investor that a newly recruited team—led by Steve Keenan, formerly an exploration manager for EOG Resources Inc.— joined Apache in 2014 to look for new resource plays in the Lower 48.

“It took a fresh look from a very talented team,” Christmann said. “[That] led us to Alpine High.” The examination delved into Paleozoic times in what was the Tobosa Basin—a bay that was covered with water in what is now the Permian Basin. The acreage Apache leased is about 400 feet above the seabed.

“The general perception was that this portion of the basin had subsided and was later uplifted when the Davis Mountains occurred, creating a deep and complex dry-gas play. The reality is that Alpine High is a relatively stable Paleo high with relatively little movement.

“This left the Barnett, the Woodford and the Penn shales all in the gas/wet-gas/oil win­dow. And a column up to 2,500 feet thick of oil-bearing potential in the Wolfcamp and Bone Spring has been confirmed above.”

The nature of the high also meant that a nominal amount of clay was deposited; the clay primarily fell to the bottom of the basin. Settling on the high was primarily sand. “That leads to better reservoir rock—easier to frack and having better-connected organics,” Christ­mann said. “This rock was always in the oil-and wet-gas-generating window.”

Apache’s announcement was of an estimated 75 Tcf of rich gas in place and 3 billion barrels of oil in the Barnett and Woodford alone on its 307,000 contiguous net acres that involve 352,000 gross. The leasehold was picked up for an average of about $1,300 per acre.

Its share price climbed from about $51 before the news to more than $59—a $2-bil­lion boost to enterprise value—and held there through November. After the OPEC oil cut news on Nov. 30, the price pushed past $65 per share. On a year-to-date basis through early December, Apache shares were outperforming many other unconventional resource-weighted producers, including EOG, Pioneer Natural Resources Co. and Continen­tal Resources Inc.

Bob Brackett, senior vice president and senior analyst for Bernstein Research, won­dered after the initial price jump, “Is this move deserved, undeserved or missing a much bigger potential?” He surmised that, “while it is early days, we lean toward the latter.” Alpine High could be worth $3 billion, he estimated, based on then-current hydrocarbon prices.

What Apache has put together contains all of the essential ingredients of a successful resource play: “contiguous and repeatable acre­age, high-rate wells with an established sweet spot, competitive well costs, access to markets, a low-cost entry … and an ability to execute a [development] program.”

On the matter of execution, “assume a [yes],” he wrote. “Capital is clearly not an issue [for Apache], and we note evidence of [its] improved completions [in the Permian Basin].” On the matter of markets, Apache will need to build some gas-processing infrastructure as well as install “the first miles” of pipe to get production to existing big pipe, “but that’s a far cry from being stranded from markets.”

Takeaway in the area has improved in the past decade as infrastructure for associated-gas production from Permian oil targets has grown. Christmann said Alpine High gas can go east to the Waha interconnect and can move north and south as well.

These connections include the Mexican mar­ket. The U.S. Energy Information Administra­tion reported in early December that daily U.S. pipeline capacity for gas exports to Mexico has grown to 7.3 billion cubic feet (Bcf) and planned capacity additions will increase that to 14 Bcf in 2018. Four new lines underway include Comanche Trail and Presidio Crossing, also known as Trans-Pecos.

Why gas?

A frequent question from investors is why Apache is initially landing in the gassier Wood­ford and Barnett at the bottom of its column, rather than the oilier Bone Spring and Wolf­camp that are higher up the hole.

Gary Clark, vice president of investor rela­tions for Apache, said it is to delineate the posi­tion. The wet-gas pay is still highly economic, and drilling to the Woodford at the bottom will hold all of the zones in its acreage. Mean­while, it is capturing data on prospective targets uphole. At top is black oil, then volatile oil, wet gas and dry gas.

“We are in the process of delineating at what depths those phase windows occur. Then, we will drill the zones we feel have the most pres­ent value for shareholders. That doesn’t neces­sarily mean oil or gas or wet gas.”

The focus is on returns, Clark explained. “If we can drill a wet-gas well that makes very strong returns that are highly competitive in our portfolio, we will drill that well all day long.”

The Barnett, which is higher up the column than the Woodford, had a higher oil cut than the Woodford in a first test. “As we move up the hole, the wells will be oilier. We don’t know how much oilier yet, but they will be oilier,” he said. Yet, “even if we don’t find any oil—and we expect to find oil—we have a highly economic wet-gas play that will be at the low end of the North American cost curve.”

Apache estimates its normally pressured Woodford and Barnett wells with 4,100-foot laterals could make a 30% before-tax rate of return at $40 oil and $2.50 gas; breakeven would be at 60 cents per thousand cubic feet (Mcf). In the overpressured areas, the rate of return could be more than 250% with breakeven at a gas price of less than 10 cents per Mcf.

D&C cost to date has been $5.5 million in the normal-pressured areas; $8 million, in higher-pressured areas. In development mode, the cost for a one-section well would likely be between $4 million and $6 million. Clark added that Alpine High’s Woodford, Barnett and Pennsylvanian-age targets have minimal to no in situ water, thus little spend is needed on produced water-disposal infrastructure.

Upon completion of field delineation, Apache can target whichever commodity pro­duces the greatest return at the time. Many other operators would have to staff and rig back up in another basin to turn to another commodity.

“It’s a unique animal,” Clark said. “I can’t think of an analogy right now in the Lower 48 that is comparable to this in scope and option­ality. We feel very fortunate.”

Apache added a few more acres in the months after its early September announcement to now total 320,000 net. “The majority of the leasing program is complete. There is some clean-up around the edges,” Clark said.

Alpine High vs. Scoop

As the oil higher up the column is a larger molecule than gas, the play’s low clay content, high silica content, permeability and porosity will help surface it, Clark said.

In a comparison of Alpine High’s Barnett and Woodford with the Scoop-Woodford in south-central Oklahoma, Apache reported that total organic content (TOC) is similar—between 4% and 10%. Both are silica-rich and were deposited in similar circumstances. These targets in Alpine High have less clay (10% to 20%), more porosity (8% to 12%), less pres­sure (5,000 to 9,000 psi), and are shallower (10,000 to 13,000 feet) and thicker (550 to 1,000 feet).

“There is high connected porosity and very high permeability for a resource play—up to 750 nanodarcy of perm,” Clark said. “That is up to three times as high as some other resource plays. We think we will have oilier wells than we’ve seen to date, and we don’t think there will be a whole lot we will have to do to flow these wells.”

The pressure “helps a lot, too.” To date, Apache has provided results on 11 wells. Early indications are that 4,100-foot laterals in the Woodford and Barnett could produce wells ranging from 1.1 million barrels of oil equiv­alent in normal-pressured areas to 2.7 million where the pressure is greater. The mix is about 12% oil, 28% NGL, and between 4 Bcf and 10 Bcf of gas.

The Woodford and Barnett oil in four wells, for example, is more than 50 degrees API, lacks paraffin and hydrogen sulfide and is 92% gasoline/diesel. Irene Haas, senior research analyst for Wunderlich Securities Inc., reported, “The company was able to use this light oil to fire up a weed wacker.”

Then and now

By 2000, not one major Permian Basin oil reservoir was located in southern Reeves County, according to a 2004 basin guide by Texas’ Bureau of Economic Geology and New Mexico’s Bureau of Geology and Mineral Resources. Across the Permian, about 3% of cumulative oil production was from Devoni­an-age formations, in which the Woodford lies on top; less than 1% was Mississippian-age, in which the Barnett lies on top.

Why is Alpine High mapped only now? Ber­nstein’s Brackett wondered the same this past fall. First, he said, it begins with terrain. “The textured [Davis Mountains] in the south … were built up from complex tectonics. [North] are the smooth areas of the Delaware Basin—smoothed out from hundreds of millions of years of sedimentary deposition. … Apache saw an area in between.”

Apache’s Clark said, “If it were easy, some­one would have found it. It required modern completions technology and 3-D seismic and just a different view of the geology here. We had to go back and reconstruct layer by layer and time period by time period to understand the history of this area, which had left this opportunity behind.”

The 3-D was crucial. “A few operators had some 3-D, but not over the entire area. They had a difficult time putting things into context. If we didn’t have the 3-D over this entire area, we wouldn’t have been able to put this together and reconstruct the whole geologic history, where to drill, how to place the wells.”

Among operators working the Barnett area in the mid-2000s was Chesapeake Energy Corp., which purchased some 165,000 net acres in southern Reeves in 2006 in the Alpine High area from privately held Alpine Inc. The package included one vertical Barnett well that was producing a commercial amount of gas.

Among operators working the Barnett area in the mid-2000s was Chesapeake Energy Corp., which purchased some 165,000 net acres in southern Reeves in 2006 in the Alpine High area from privately held Alpine Inc. The package included one vertical Barnett well that was producing a commercial amount of gas.

“The shales are much thicker than in the Fort Worth Basin (Barnett), Arkansas (Fay­etteville) or southeastern Oklahoma (Wood­ford),” it reported. In comparison with the Fort Worth Barnett, it estimated 600 Bcf of gas in place—up to two to four times more.

“However, it is approximately twice as deep, [thus] well costs will be higher, and recovery factors are currently unclear,” it added. Chesapeake exited the Permian in 2012.

Several other operators were looking at the Barnett and Woodford in the county as well—most of them off the structure Apache has identified. The play-starter, Burlington Resources Inc., had re-entered a shallower vertical in northern Reeves County, accord­ing to an Investor report at the time. From the Barnett, the well came on with 2 million cubic feet per day. Burlington had 350,000 net acres. Other operators included Hallwood Petroleum LLC, which had Barnett success in the Fort Worth Basin and sold that to Chesa­peake, and Petro-Hunt LLC, which went on to have Bakken success in the Williston Basin.

North of these were EnCana Corp., which gained its position from Tom Brown Inc.; EOG; Southwestern Energy Co., which was also working on the Fayetteville; and Quick­silver Resources Inc. and Range Resources Corp., which were also in the Barnett. The latter was building its Marcellus program.

Apache reported in September that the perception of the Barnett and Woodford in the area was that they contained dry gas, high clay content and depositional complexity. Instead, Apache found that—on the high— they contain wet gas, low clay content and depositional stability.

The play “never took off,” Wunderlich’s Haas wrote of the mid-2000s attempt. Within a few years, “the crash in natural gas prices finished [it] off.”

Sidelines, questions

Tudor, Pickering, Holt & Co. analysts reported in mid-October that delineation of the play is a near-term governor on Apache’s enterprise value “as investors will likely be in well-watching mode for the next several quarters.”

It “could be just what the company needs—a sizable, contiguous and repeatable resource. However, the need for more delin­eation data and the recent run-up of the equity leave us on the sidelines,” they concluded.

Meanwhile, Mike Kelly, senior analyst for Seaport Global Securities LLC, wrote that some doubters “question how Apache’s knowledge of the acreage could be superior to its surrounding Permian peers.” From meeting with Apache management, Kelly and the SGS team found that it is the only operator that has shot 3-D seismic over all of the leasehold and pulled core.

Fewer than 120 wells in the past had been drilled into the Barnett and Woodford in the area. Kelly wrote, “Thus, those who are con­demning the acreage are doing so without doing their homework.”

What he and his SGS colleagues are look­ing for now are results from longer laterals, tests of uphole Pennsylvanian-age shales, big­ger frack jobs, delineation of the southernmost portion of the leasehold and more Wolfcamp and Bone Spring results.

“Apache’s estimated Alpine High count of 2,000 to 3,000 locations doesn’t bake in any credit beyond the Woodford and Barnett for­mations, despite two strong results from the Wolfcamp and Bone Spring,” Kelly reported. “Management believes it could ultimately have up to 2,000 potential wells to drill in these formations.”

Haas reported that the overlying Bone Spring and Wolfcamp may be thin in the Alpine High area. But, she added, “producers have been successful in tapping zones as thin as 20 feet in the Permian and the Eagle Ford, so thickness is not a big factor in defining productivity.”

What’s next

Apache increased its 2016 spending on the play from less than $100 million in January to $500 million in September, representing 25% of its 2016 capex budget. Some 40% was spent on infrastructure. Christmann didn’t have guidance for 2017 at press time.

The wells take less than a month to drill, so a four to five rig pro­gram would produce between 60 and 80 wells in 2017. “We’re blessed to have 4,000 to 5,000 feet of pay here from Woodford to Bone Spring,” he said. “It’s a game-changer for Apache, and I think it will be very material for the industry.”

For holding acreage and testing, Apache’s laterals have averaged 4,100 feet. Also, com­pletions have been small, standard reci­pes as the work now is to “tell us about the rock and help us discern the boundaries of the play.” In time, laterals will become longer and the fracks bigger as Apache understands the rock “and how we want to develop it.”

He estimates Apache has at least two land­ing zones in the Woodford, three in the Bar­nett and three in Penn-age shale—for eight in the bottom 1,600 feet. “On just a high-graded portion of our acreage, we’re looking at, initially, six wells per section. That number could go higher.”

And it has the overlying Wolfcamp and Bone Spring to produce as well. “The verti­cal dimension of this play is unlike anything we’ve seen. You have five formations and multiple landing zones, so the math can be pretty large in terms of the number of loca­tions,” Christmann said.

The one-section laterals have been drilled in about 48 hours, he added. “So it will be easy to stretch this out to 8,000 feet and 10,000 feet without a lot of incremental cost. One of the signatures of this play is that the well costs are going to be very, very low.”

Bernstein’s Brackett reported that, rather than Apache operating just defensively in the oil-price downturn, the announcement “rep­resents a somewhat different tack—a new strategic bet.”

Christmann said, “It shows the ability we have to bring forward a play organically at a time when a lot of companies are out paying very high prices for acreage.”

Are there more Alpine Highs to be found in the Permian Basin? Haas concluded, “We don’t think so.” Myriad circumstances are needed to generate the producibility.

“After eliminating areas that have unfavorable parameters, we end up with discrete pockets of productive areas. Therefore, these plays tend to have compact footprints, are hard to replicate and do not extend for miles and miles.”

Haas added that, while a play like Alpine High is hard to find, “for those producers, such as Apache, that are willing to take the risk and have the right staff to tackle the tech­nical challenges, being contrarian can result in significant home runs.”