Four glowing rigs stand side-by-side on a rise southwest of Midland, silhouetted against an orange sunset bursting through low clouds. A late afternoon storm sparked with lightning rolls across the West Texas plains from the northwest and blots out the postcard scene. Cold, fat raindrops dampen the ground as daylight fades.

The blue norther, lore in the annals of Texas weather, could be a metaphor for the current plight of the oil and gas industry. A low pressure system of cold and windy commodity prices has settled in across the industry, although a recent uptick in crude may signal a break in the clouds.

Those rigs, operating for Pioneer Natural Resources Co., might be the only four in such tight formation across the nation, as but a handful of operators are running that many or more in any given play. The U.S. land rig count has dropped 72% since first-quarter 2015, according to data from Baker Hughes Inc., from a high of 1,811. Just 502 rigs remained active as of the end of February, yet with the announced budget cut guidance for 2016 E&P capex, that number is likely to continue a downward trend.

While the economic cores of all other shale oil basins have shrunk or disappeared as oil has hovered around $30, the resilient Permian holds fast with positive returns, even if only marginally.

“The Permian Basin is the low-cost oil basin at this point,” said Chris Stevens, vice president, equity research analyst, with KeyBanc Capital Markets Inc. “Most of the Lower 48 oil plays are extremely challenged in the current environment, but the Permian is the basin that generates the best returns.”

Apache Corp. CEO John Christmann, speaking before the Society of Petroleum Engineers business development group in January, deemed the company’s 1.6-million- net-acre Permian position “the crown jewel” of its international portfolio, where “in the best of these plays, all the wells work sub-$40.” Cash flow, not economics, is the challenge in today’s environment, he said.

The breakeven

Best returns don’t necessarily equate to drilling activity. With oil trading below $40, almost every Permian operator has pulled back on activity to the point that production is either flat or down, Apache included. There is little incentive to drill with oil in the low to mid-$30s, said Stevens.

“Select areas of the basin can generate a decent return, but in most cases it’s still challenging. Looking at just wellhead economics, some areas generate close to a 20% rate of return, but the behavior of most operators makes it apparent that returns are pretty thin.”

Permian non-vertical rigs topped out at 355 in first-quarter 2015, but just 141 remained in action at the end of February, per Baker Hughes.

When facilities and infrastructure are rolled into wellhead economics, the incentive to grow production wanes. At $30 oil in February, the Permian was essentially at the point of breakeven—and nobody wants to drill wells at breakeven or just above, contends Stevens.

“Nobody wants to drill their best inventory when oil prices are low. There is more value in waiting to see if commodity prices increase a little to be able to generate that 30%, 40%, 50% rate of return. We’re not far from that level where operators would begin to increase activity. At $40 a barrel, that’s where Permian operators would begin to increase activity at the margin, because returns in the better areas can exceed 30% to 40%.”

RSP Permian Inc. CEO Steve Gray expressed that mindset in the company’s fourth-quarter conference call.

“If you run a flat case, the present value of a well that you drill at $30 a barrel is squished compared to what the present value is in the $40 drill. The PV of the well goes up eight times or 10 times when you run from $30 to $40 or $50 a barrel. So when we look at present value … [at] $40, it becomes an attractive investment, and below $40, it's a skinny return.”

A step ahead

When Bryan Sheffield started Parsley Energy Inc. as a contractor to operate other investors’ wells in the Midland Basin, he envisioned growing it into a $20- to $30 million company that would drill five vertical wells a year. Taking advantage of a downcycle in oil prices, Sheffield picked up leases and working interests in the heart of the Midland.

But the hype of the Wolfcamp play was so good that the company couldn’t stop growing, and when EOG Resources Inc. and Pioneer Natural Resources began drilling prolific horizontal wells to the north and south of its acreage, the company’s value skyrocketed. Today, the Austin, Texas-based producer trades on the New York Stock Exchange with an enterprise value of $3.5 billion and intends to drill over 60 horizontal wells this year.

Considering industry headwinds, Sheffield seemed comparatively upbeat in the company’s fourth-quarter conference call, even announcing a push for an additional 40% production growth in 2016, following a 55% increase in 2015. Further, Parsley is projecting a 60% ramp-up in oil volumes this year while keeping capex at approximately $400 million.

Although contrary to the trend amid depressed prices of preserving capital at the expense of production growth, Parsley’s strategy is straightforward, he said. Even today, the company is able to achieve 35% wellhead returns at strip prices.

“It’s very economic in our neighborhood” in the center of the Midland Basin, he said.

A robust hedge position that covers 100% of anticipated oil volumes enhances Parsley’s economic profile, adding approximately $10/bbl at current prices.

Given that the company paid off all its debt with a $900 million raise in a well-timed IPO in mid-2014 and bolstered the balance sheet with $250 million of cash via two equity issuances in the second half of 2015, Sheffield believes sustaining operational momentum adds greater value than slowing down.

“Operational momentum is an elusive phenomenon, and we’ve worked hard to minimize the friction costs associated with starts and stops,” he said. Plus, “we’re at a unique point in our life cycle, and if we pull back too much, it could take several months to resume the same growth trajectory once oil recovers.”

Parsley controls close to 90,000 net acres in the Midland Basin but focuses its activity in north Upton and northwest Reagan counties. There, the company has drilled consistently prolific horizontal wells targeting the lower portion of the Wolfcamp B zone. Recent well results show 30-day IPs in the range of 1,400 to 1,900 bbl/d.

Sheffield identifies north Upton as the original core of the company’s position, where the Wolfcamp is deepest, but the company has been steadily adding northwest Reagan acreage to the portfolio, including a $148 million acquisition in December.

“We’re starting to realize that the Wolfcamp is just as good on the other side of the county line,” he said. “It’s a recurring theme: We’ve been acquiring acreage in northwest Reagan for the past year and a half, and now we’re seeing similar results to north Upton County.”

EURs on the acquired properties are tracking above Parsley’s 1 million barrels of oil equivalent (MMboe) type curve.

And with the Wolfcamp B at 550-feet thick, Sheffield projects future development to include two flow units within the interval. Recently acquired wells drilled into the Upper Wolfcamp B zone in Reagan County matched Parsley’s Upton County Lower B wells at 1,400 to 1,600 boe/d.

“We’re very excited about the double B,” he said. “We see a lot of potential for multiple Wolfcamp B targets.” Parsley has recently been drilling pads that include both Wolfcamp A and B wells, with great success.

“That’s a perfect example of what the Permian Basin is about. The stacked pay just continues to give optionality.”

With $770 million of liquidity, Parsley is well-capitalized even given its current growth trajectory, especially if the oil price cycle plays out as Sheffield expects, recovering to the mid-$40s by second-half 2016. At that point, Permian operators will come alive with rig additions, he forecasts, adding production and capping a price recovery. Operators in other basins need oil in the mid-$50s, he projects, which will be much harder to come by.

“There is going to be this happy place for Permian operators, but we’re a victim of our own success. If we get to the $50s, other basin operators will add rigs too, and it just seems there is a cap. I do think Permian players will survive and prosper in that type of oil price band.”

Parsley’s balance sheet and hedge book put the company in an enviable position, and it plans to hold steady in 2016 with four rigs running.

“Our hedging program and capital markets activity have been sized to allow us to drill through a downturn of the magnitude and duration we are experiencing, without moving outside our leverage and liquidity comfort zones. These decisions bought us time,” Shef­field said. “This is an opportunity for us to stay a step ahead.”

Trading in the verticals

Midland-based private E&P CrownQuest Operating Co. considered itself one of the premier vertical operators in the northern Midland Basin leading up to the oil price crash in late 2014. The company, formed in 1996, was running 13 rigs at the time and was closing in on its 1,000th well. The wells targeted 10 to 14 stages in the column from the Upper Spraberry through to the Mississippian-age formations. At a $2 million per well average cost and 175,000 barrel EURs, “the results were highly economic,” said Lee Dunn, CrownQuest vice president of business development. Average returns—all-in—were in the 30% to 40% range. “We were really proud of our results.”

Reality affects even the best producers and, with lower well costs baked in, the vertical wells struggled to break even as the economic climate changed. Dunn ran economics on strip prices in mid-February at $27 going to $40 over five years, and “they’re negative at that. Almost everything is.”

By the summer of 2014, it had become apparent that the northern Midland Basin was changing, with Parsley and others drilling horizontal wells. CrownQuest drilled its first horizontal well in late 2014 and has completed 11 more since.

“The horizontals actually generate a positive return in the current environment,” he said. “We made the transition because we became convinced they made sense economically to the verticals. And in areas where the verticals were not compelling, the horizontals were—significantly. The horizontals are amazingly good.”

CrownQuest holds 100,000 acres in Howard, Glasscock, Midland and Martin counties, a 40/60 straight-up partnership with private equity firm Lime Rock Partners under the nameplate CrownRock LP. Its concentration is in Howard County.

With the western Midland Basin Wolfberry play locked up when the company began leasing in 2007, CrownQuest turned its eye toward the eastern side of the basin, which “fewer companies [were] paying attention to” at the time, he said.

“When we first started, we felt like Martin and Midland counties were going to be really good, superior to everything else. That so far has not been the case.”

Of course, the target at purchase was reserves from the vertical column, and the eastern basin had productive zones “all the way down to the Miss. There are more targets” than the western half of the basin, he said.

At the time, Dunn deemed a large portion of Howard County “bad vertical stuff” to be avoided. In fact, the company drilled 15 vertical wells in northwest Howard County, and “they were an apocalypse. Oil was $90, and we were losing money. Really, really bad.”

When Athlon Energy Inc., subsequently acquired by Encana Corp., began drilling in Howard County east of CrownQuest’s acreage, Dunn believed the acreage wasn’t nearly as good as CrownQuest’s.

However, for horizontal drilling, “it doesn’t seem to matter.” While only two or three benches are productive in the region—a nonstarter for vertical drilling—the horizontal wells are showing EURs of around 1 MMbbl per well. “The horizontals Athlon and Encana have drilled in central Howard County have been amazing.”

Likewise, Tall City Exploration LLC and Element Petroleum LLC sold out their Howard County position to Chinese-backed Blue Whale Energy for more than $1 billion. “They delineated a lot of acreage horizontally that we knew didn’t work vertically and got paid handsomely for the position. It’s really a great story.”

By the time they sold, Tall City had delineated the Wolfcamp A, Wolfcamp B and the Lower Spraberry.

“That acreage is worthless as a vertical target and worth more than $32,000 an acre horizontally,” he said.

Since drilling its first horizontal well, the company has drilled eight Wolfcamp A wells, three Wolfcamp B wells, and is drilling its first Lower Spraberry well.

“When we put this acreage together, we didn’t think horizontals would work on it,” Dunn said. “We’ve been proved wrong; it continually gets better as we move through time.”

Dunn deemed the wells “highly economic at current prices,” with all posting initial production (IP) rates of more than 1,000 bbl/d and averaging more than 1 MMboe EURs. Well costs average $6 million all-in for a one-and-a-half-mile lateral.

“The horizontal results have been significantly better than the vertical results, even in the places where the verticals were really good.”

The challenge with drilling horizontals in the Midland Basin, though, is not in the technology, but in putting together units to drill longer laterals. With more than 70 years of mineral ownership in the basin, “maybe you can find the owner, maybe you can’t. A lot of effort goes into making these lanes for the horizontals that you don’t have to do for the verticals.”

The Midland operator currently features 700 wells and 25,000 bbl/d of production. Although drilling at a slower pace than its 2014 program, CrownQuest still plans 20 horizontal and 40 vertical wells in 2016 based on a $320 million capex plan. Being almost 100% hedged at $80 oil makes that possible, a practice it began in 2011 when oil was higher.

“We felt like the biggest danger was the inability to drill the wells to hold acreage if the price went down. It worked out great this year, but we lost a lot of money for a long time doing this.”

He has no regrets, he said, “because what’s happening now happens. The oil business is about staying in the phone book—surviving. Right now we’re treading water, holding acreage, drilling what we have to.”

In a downturn, the Permian Basin is the last place to go down and the first to come back when prices recover, he said. In the meantime, everyone in the basin is going to cash flow breakeven.

“This year is going to be bad,” said Dunn, “but Permian operators as a group are in a much better position. We’ve always loved this basin. There’s no place like the Permian.”

Delaware dreaming

Following the February NAPE Summit in Houston, analysts with Seaport Global Securities LLC reported their biggest takeaway from the exhibition was an affirmation that the Delaware Basin continues to get more attractive—on a weekly basis—suggesting it might ultimately become a better play than the Midland Basin.

“Well-funded and operationally capable private operators Jagged Peak, Brigham Resources and Luxe Energy pointed to maps with 1 MMboe-plus EUR wells spotted across the southern Delaware Basin,” the analysts wrote post-show, “and provided what we believe is an extremely strong endorsement of Parsley Energy’s 30,000 net acres.”

In a February report, Wunderlich Securities analyst Irene Haas dubbed the Delaware “larger than life.”

In a $30 to $35/bbl environment, “we are still seeing economic returns across various parts of the basin—there is no single sweet spot. The Delaware Basin is prolific, and for those producers with a combination of improving productivity and sustainable efficiency gains, this basin will be one of the most resilient despite low crude prices,” she wrote.

Matador Resources Co. is one public operator driving forward. As long as oil stays above $30, it plans a three-rig program and 50 wells in 2016 in Eddy and Lea counties, New Mexico, and Loving County, Texas. “The Wolfcamp A offers a very solid rate of return, and that’s going to be the bulk of our drilling,” Matador CEO Joe Foran said at the company’s analyst day in February.

In contrast, the company is running no rigs in the Eagle Ford, although Foran said the economics per well are essentially the same as the Delaware wells. The difference is the number of potential productive formations secured with each well.

“You just have a host of formations that add millions of barrels with each well drilled, and potential value in those zones that are proved, probable and possible reserves. That is just the big added advantage: You get a whole lot of other good zones to consider going forward that presently the Eagle Ford doesn’t have.”

Scratching the sub-surface

Alongside majors and public independents staking claims, private-equity-sponsored companies have found a home in the emerging southern Delaware Basin, where land is more readily available than in its Midland Basin counterpart. Jagged Peak Energy LLC, formed in 2013 and backed by Quantum Energy Partners, is among the flurry of players testing the southern fringes of the Delaware—with success.

“We like the Delaware because there are just so many pay horizons,” said Joe Jaggers, Jagged Peak CEO. “You have so much potential that if one thing doesn’t work or work well, you could always find something else. It was clear to us early on that we wanted to be here, and be here badly.”

Jaggers earned his stripes at Bill Barrett Corp. and later built and sold Ute Energy in the Uintah Basin for $1 billion. He pieced together his 60,000-acre Delaware position in Ward, Reeves and Pecos counties in three separate self-sourced deals from Whiting Petroleum Corp., Clayton Williams Energy Inc. and Dallas private KEW Drilling.

Denver-based Jagged Peak drilled its first horizontal well in fourth-quarter 2013, and now has nine drilled and completed, most in southern Reeves County, on a steady program of one to two rigs. Daily production stands at more than 6,000 boe/d, 85% oil.

“We’ve only scratched the surface,” Jaggers said.

Thus far the company has almost exclusively targeted the Wolfcamp A with 7,500 to 10,000-foot laterals, and one experiment stretching to over 12,000 feet. “We’re at the absolute limit of where we can push the coiled tubing,” he said of that well.

Doubling the lateral length from one mile to two miles provides about a 1.75 times correlation to an increase in production.

“Once we’ve gotten to 10,000 to 11,000 feet in the vertical, we just think it is more cost effective to take the lateral as long as you can physically take it, and our land position sets up well for these longer laterals,” he said, noting the drilling challenges occur in the Delaware sands section of the vertical wellbore—with overcharged water and H2S issues—not in the lateral. “These laterals drill easy.”

The wells take 40 to 45 total days to drill. Jagged Peak’s 24-hour IPs have ranged from 1,200 to 1,800 boe/d, with one as high as 2,400. Results benefit from overpressuring in the reservoir, although the company practices choke management at the wellhead.

“We’re in the most overpressured part of the basin. Our first long lateral well didn’t go onto artificial lift until 15 months after initial production.”

Average EURs fall at 1.1 MMboe. And even at $10 million to drill and complete, the wells are economic today, he said.

“That’s fortunate as to where we are. At strip, at those costs and EURs, we’re looking at a roughly 20% rate of return.”

At $55/bbl, the rate of return jumps to 60%, a level he hopes to achieve this year.

Jagged Peak has drilled one well into the very top of the Wolfcamp B that’s a great well, as Jaggers characterized it. “Maybe our highest EUR,” he said. The company plans another test into the B this year.

The Delaware Wolfcamp is much thicker than the Midland Wolfcamp, he said, another selling point for entry. He believes the A section is thick enough for two landing zones and the B section can take multiple laterals. Upside potential in the column includes the Wolfcamp C, the First, Second and Third Bone Spring and the Avalon. He estimates over 200 MMbbl of oil in place per section across all zones.

The company is currently drilling just to hold the position together before beginning a development program involving stacked, staggered laterals in various zones. He identifies over 1,100 drillable Tier 1 locations, but admits that number doesn’t include all zones.

“This land has a scarcity premium to it,” he said. “You sure don’t want to let it get away.”

Water management is a big priority for Jagged Peak in this remote region of the West Texas desert. The company bought land with water rights to be able to drill and produce non-potable water for its completions. Two massive storage facilities hold a million barrels of water each, and it has drilled or converted old wells for water disposal. Completions use a blend of half recycled produced water and half new water.

“We pipe it everywhere. We’re proud of the fact that we put zero trucks on any of our wells for either delivering water for a frack job or picking up produced water,” he said.

Jagged Peak released a rig in February and is drilling “steady as she goes” through 2016 with one rig on an 11-well program. “We need to test these different concepts.”

Jaggers said the Delaware Basin holds up the best among Lower 48 basins.

“It’s one of the few places that you can still drill better-than-cost-of-capital wells, and the multiple pay opportunities give you so much inventory for the future. To me, it is the premier basin in the U.S. There’s nowhere else I’d rather be.”

Five zones flush

When Centennial Resource Development LLC chief executive Ward Polzin determined his upstart company in 2013 couldn’t be competitive for acreage in the Midland Basin, he turned his efforts to the Delaware Basin, which had “lots of running room, and we thought the rocks were as good or better,” he said.

“The Wolfcamp is way overpressured relative to the Midland Basin, and you get more oil out per lateral foot. But it costs a bit more to drill it. That’s always been the knock on the Delaware—it costs more.”

Avoiding federal lands in New Mexico and the gassier phases on the Texas side of the border, Denver-based Centennial locked in a deal with Atlantic Resource Co. and related nonop owners in Reeves County to aggregate some 42,000 net acres.

“The difficulty three years ago was there weren’t a lot of horizontal wells drilled in southern Reeves. There was a good bit of data from vertical Wolfbone wells—just enough vertical control to understand the geology, but not too much to deplete those areas.”

At the time, the southern Delaware looked unproven. Polzin set out to prove its worth.

“We felt we could be competitive in Reeves County. The vertical data showed these horizontals, with time and figuring out the fracks, could turn into something really good.”

After securing the acreage in April 2014, the company, backed by Natural Gas Partners and Carlyle Group, began an intense drilling program, deploying four rigs and “rock and rolling” through the delineation phases, said Polzin. The company “scaled back hard” and briefly dropped to no rigs when the price collapsed in late 2014 before adding one rig back in the spring, where it has held ever since.

Today, Centennial has drilled 55 horizontal wells and has established production in five different zones—the Upper and Lower Wolfcamp A, the Wolfcamp B and C, and the Third Bone Spring sands. Most of the landings have reached the Upper and Lower Wolfcamp A flow units, but “there’s not just one Wolfcamp zone that’s dominant right now,” he said. However, “the Wolfcamp A has the best economics right now, so that’s where we’re drilling today.”

Typical 30-day IPs average 1,200 boe/d with 70% to 80% oil, but “just enough gas to have energy in your system.” EURs approach 800,000 boe on 4,500-foot laterals. Well costs are about $6 million currently, including facilities, about half of what they cost in the early program.

Polzin holds actual economics close to the vest, but indicated “our position is solidly economic at today’s strip, no question. We feel very competitive with those rates of return being talked about in the Midland Basin.”

At press time, the company had drilled but not yet completed its first extended lateral at 9,500 feet.

Centennial also recently tested a stacked/ staggered concept in the Upper and Lower Wolfcamp A, at 880 feet apart per zone, and 440 feet between wellbores and a vertical distance of 175 feet. This two-well pilot simulates an 11-well development program per unit with six on top and five staggered below.

“Those two wells turned out great,” he said, “with both of them easily in our top 10 wells.”

In addition to the five tested and productive zones, Polzin noted the Third Bone Spring Shale—not the sands—is 1,000 feet thick and is the geologic equivalent of the Lower Spraberry Shale in the Midland Basin.

“Two years ago in the Midland side, we thought the Wolfcamp was the best zone, and now the Lower Spraberry is the best. Can the Third Bone Shale become the Lower Spra­berry for us? We don’t know. We just haven’t had time to test it yet.”

Then there’s the Second Bone Spring Shale, the equivalent of the Middle Spraberry, also 1,000 feet thick. “We’re itching to get there.”

Centennial estimates it has 1,800 drilling locations across the five identified zones, based on six wells per section, and produces 7,500 boe/d currently. But it only needs to drill four wells this year to hold expiring acreage. A $40 oil price might inspire it to add another rig, but sustained low $30s also might motivate dropping the last rig once acreage is held.

“We’re not going to try and grow production, right?” he said. “There’s just no need to do that. We’ll drill what we have to drill, and play it conservative. We’ll see what oil prices do.”

Excitement warranted

In 2013, Parsley stepped out into the southern Delaware Basin with the acquisition of 30,000 Pecos County acres picked up at auction for around $500 per acre. With most Delaware horizontal activity to the north and west, Parsley acquired 3-D seismic data and drilled three vertical well pilots before the price collapsed. The company deferred exploratory projects through most of 2015, but curiosity and positive data points prevailed, and the Austin E&P drilled one operated well and participated in a nonoperated well before year-end.

“We had the science in-house, so we made a risky decision to move forward with two wells. It would either be a home run or a bust,” Sheffield said.

The operated Trees State 16-1H was a home run, flowing 1,550 bbl/d on a 24-hour rate from a 4,500-foot lateral at a drilling and completion cost of less than $6 million. The well tied the company’s second-best 30-day IP per 1,000 feet of lat­eral at 252 boe/d.

“We drilled a barn-burner right smack in the middle of that 30,000-acre block,” he said.

The nonoperated well, drilled in northeast Reeves County with an 8,300-foot lateral for $8.5 million by Jagged Peak Exploration, yielded an IP of 2,175 boe/d over 24 hours.

The thickness and pressure of the Wolfcamp in the Southern Delaware Basin are similar to those in the Midland Basin Wolfcamp, he said, but costs will need to come down for the basin to compete for capital with the Midland program. He has no doubt that will happen in time. Parsley has allotted 7% of its total D&C capex to the Delaware side this year for a three-to-five well program.

“If the rates hold up and we see returns, then I do see it competing with the Midland Basin, maybe around 20% of our development capital in 2017.”

Sheffield would like to add to his portfolio going northwest of its northern Pecos position toward current activity—“we’re definitely on the prowl”—but believes east and south are less promising. The Permian’s Central Basin Platform defines the eastern fence, and complicated faulting the southern edge.

“There’s a line to our south that we don’t want to cross,” he said. “There is too much faulting, and past the faulting I think the Wolfcamp is just baked differently.”

But with 3,000 feet of Wolfcamp and the Bone Spring, Pennsylvanian, Mississippian and Woodford horizons screening prospective on the logs, the company has plenty of Dela­ware upside to chew on.

“Our first horizontal well was a huge success,” Sheffield said. “It’s becoming clear that our excitement has been warranted.”