The Eastern Eagle Ford

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

In mid-2014, the eastern window of the Eagle Ford was a hotbed of activity. Operators ranged from Anadarko Petroleum Corp. (NYSE: APC) to Occidental Petroleum Corp. (NYSE: OXY ) In addition to the Eagle Ford, some E&Ps were targeting the Austin Chalk, Woodbine, Buda, Georgetown and Glen Rose.

The area had up to 30 rigs at work pre-2015. With the downturn, that faded. Some producers folded. Others sold, particularly to devote to the Permian Basin what capital they could muster.

But securities analysts report that an eastern Eagle Ford renaissance is underway among those who stayed with the leasehold. And it’s timely: Subash Chandra, senior equity analyst for Guggenheim Securities LLC, wrote that the cure for “Permi-phobia”—that is, the fear of takeaway constraint—is the Eagle Ford.

Seaport Global Securities LLC (SGS) analysts reported this summer that, after speaking with most of the 46 operators the team covers, “the non-Permian names—and those who invested in them—are loving life.”

Chandra picked the Eagle Ford over the Bakken Shale and Oklahoma’s Scoop/Stack plays on multiple measures, including that it’s oil and it’s nearer to export markets. The Eagle Ford “should get more credit,” he concluded.

Among the Eagle Ford, Chandra ranked WildHorse Resource Development Corp. (NYSE: WRD) highly for its “oil cut, leverage, undeveloped inventory and basis.” The company is active on the eastern end of the play.

SGS head of E&P research Mike Kelly initiated coverage of WildHorse in June with a Buy. WildHorse’s first-quarter cash margin of $37.15 per barrel of oil equivalent (boe) ranked eighth best out of 70 companies reviewed in his study.

SunTrust Robinson Humphrey (STRH) and several other firms initiated coverage this summer as well. Meanwhile, Imperial Capital LLC initiated coverage of new Eagle Ford entrant Magnolia Oil & Gas Corp. (NYSE: MGY), led by former Oxy CEO Steve Chazen, and STRH initiated coverage of Lonestar Resources US Inc. (NASDAQ: LONE), which operates throughout the Eagle Ford.

Less Than $2,000/Acre

Privately held at the time and backed by Natural Gas Partners and The Carlyle Group LP, WildHorse stuck with the play through the downturn. Chairman and CEO Jay Graham told Investor, “WildHorse was the last company still operating a rig in Burleson County during January of 2016.”

As operators were exiting, Graham picked up leasehold from Anadarko, SM Energy Co. (NYSE: SM), Clayton Williams Energy Inc., Comstock Resources Inc. (NYSE: CRK) and others for more than $1 billion, forming a 404,000-net-acre consolidated position in the old Giddings Field in Burleson County and spilling into Lee, Washington, Brazos, Milam and Robertson counties.

It went public in December of 2016 and became a pure-play Eagle Ford operator earlier this year, selling its North Louisiana gas asset for $217 million. It’s the largest leaseholder east of the San Marcos Arch.

First-quarter production was 40,400 boe/d, 88% liquids. Proved reserves at year-end were 386 MMboe. It has a downhole science project underway. And its own sand mine is expected to deliver a first truckload by the end of the year.

“As a private-equity-backed operator, you look for low entry costs, room to grow, room to consolidate,” Graham said. He previously formed and sold WildHorse I to Memorial Resource Development Corp., which he sold to Range Resources Corp. (NYSE: RRC) in 2016 for $4.2 billion in stock.

“I’ve always chased lower PDP [proved, developed, producing] properties—something that has a lot of development potential. Everything came into play in Burleson County. It was under the radar,” he said.

Acreage was picked up at an average of less than $2,000 an acre. Drew Cozby, WildHorse executive vice president and CFO, said, “There were six public companies out here; it wasn’t core to any one of them. But if you own all six of the positions, which basically we do now, you really have a major footprint in the Eagle Ford.”

Graham said, “This had always been a legacy Austin Chalk area. It hadn’t been an Eagle Ford area.” As old Chalk wells were being shut-in beginning in early 2015, “leases started opening back up.”

More Sand

Oilfield service costs had declined greatly, so WildHorse started pumping more sand. “As everybody else was shutting down, we continued to drill. We never dropped all of our activity.”

The earliest jobs were 800 and 1,000 pounds per lateral foot. Pre-2015, operators didn’t pump more than 1,500 pounds per foot. WildHorse began pumping 3,700 pounds.

Graham said, “We took it to the Generation 3 design. That’s one of the things that gave us an operational advantage. No one else had pumped a Gen 3 well in the area. So, when we were out acquiring and consolidating the area, we had the inside knowledge of what the potential of a 3,700-pound-per-foot frack job could unfold.”

In the first quarter, it brought on three Eagle Ford wells averaging 24-hour IPs of 941 boe/d, 90% oil, and 6,400-foot laterals. The wells are the farthest northeast in its acreage that it’s used the Gen 3 completion to date.

SGS’ Kelly reported that “WildHorse has cracked the East Texas Eagle Ford code” and the “re-emerging Austin Chalk [is] a compelling kicker.”

“Most investors and industry professionals were convinced,” Kelly wrote, “that East Texas Eagle Ford returns would never be economic, let alone competitive, [at post-2014 oil prices].” WildHorse’s Gen 3 completion recipe, with 117 of these at first-quarter-end, “now has a body of data that should prove the doubters wrong.”

To further reduce the cost of its Gen 3 completions, WildHorse is building an infield sand mine that is expected to be in operation by the end of this year. Nameplate capacity is about 2 million tons a year; the resource is 85 million tons. It’s 90% 100-mesh Texas white; the balance, 40/70.

The San Marcos Arch separates the western and eastern Eagle Ford generally at Hays, Caldwell, northern Gonzales and Lavaca counties.

The type and ratio are what WildHorse uses in its completions; the 40/70 is used in the tail. About 30% of the mine’s capacity will be available for sale.

STRH analyst Welles Fitzpatrick initiated coverage of WildHorse in July. WildHorse’s sand mine “should pay back in just 140 wells—or 1.3 years at the current (completion) pace,” he reported. Savings per well may be between $400,000 and $600,000, netting a 10% improvement in internal rate of return.

With its own sand mine, WildHorse could change to 5,000 pounds per foot. Its average lateral length this year will be slightly more than 6,500 feet.

Graham said, “We’ve already taken it to 5,000 in a few areas and—once we have our own sand mine and we drop the cost to 70% of what sand costs us—you’ll see us continue to push the limits on concentrations.”

Science Project

WildHorse is also participating in a Department of Energy-sponsored study led by Texas A&M University. TAMU petroleum engineering professor Dr. Dan Hill brought the proposal to Graham, a TAMU alum. “It was a pretty competitive process and we won the bid,” Graham said.

The $8-million grant involves three of WildHorse’s Eagle Ford wells—one for refracking and two new wells—into which fiber optics and bottomhole pressure gauges will be placed permanently downhole to assess well performance.

Altogether, the data gained should indicate where the frack went. “Our hope is, with the fiber optics and microseismic, we can really look at where we’re initiating the fractures and how effectively we’re fracking all of the clusters.

“We all know we’re not effectively fracking every one of those clusters. We can really hone in and get more of those perf clusters effectively stimulated. The application of new technology to older plays is a winning bet.”

The lessons will go a long way; WildHorse still has a lot of wells to drill. “Many of those positons in the legacy part of the Eagle Ford [to the west] are already 50%, 60%, 70% developed; we’re 5% to 10% developed. We’re in the very, very early stages of development in Burleson County.

“By getting the science in now, we can really drive the development more efficiently, beginning at 15% and 20% developed as opposed to 80% developed.”

WildHorse will have exclusive use of the data during the study and until the results become public. Graham said that could be fairly quickly, “which is great, because I’m all about industry being successful. When the others around you are successful we all help each other.”

Enter Chazen

Eagle Ford operators are getting a bit of help from the entrance of Magnolia Oil & Gas’ Steve Chazen. While the former Oxy CEO’s entry represents more competition for acreage, Graham and other operators Investor spoke to were glad to see Chazen pick the Eagle Ford to deploy his special purpose acquisition company (SPAC) capital.

The SPAC, TPG Pace Energy Holdings Corp., bought EnerVest Ltd.’s South Texas property, producing some 46,000 boe/d, 62% oil, 78% liquids, for $2.7 billion in cash and shares. EnerVest will continue to operate under a long-term service agreement. The deal closed on July 31.

Some 14,000 of Magnolia’s net acres are in Karnes County in the core of the oily Eagle Ford window; the roughly 345,000-net-acre balance is held by the wet-gas Buda Formation underlying the Chalk and Eagle Ford in Giddings Field.

Of the production, about 36,000 boe/d is from Karnes County and 10,000 from Giddings Field.

WildHorse’s leasehold, which is entirely in the eastern Eagle Ford, sits in the middle of Magnolia’s.

Graham said Chazen “wasn’t the first one in. He’s kind of the last one in. But what Magnolia and Steve Chazen bring is Chazen’s name. It’s an affirmation of what we’ve been saying [about the area].

“But, certainly, I’ll be the first to say that, when Steve Chazen goes to New York and says something vs Jay Graham going to New York and saying something, Chazen has a bit more history, and people know him better.

“It definitely brought some credibility to the area.”

While 96% of Magnolia’s leasehold is for Chalk in the Giddings Field area, Chazen told Investor in an interview this spring that he didn’t buy the EnerVest position for the Chalk. “I know the oil is in place there,” Chazen said.

“They’ve started to figure out how to get it out. Whether it turns into a big deal or a medium-sized deal or a small deal, I don’t know. But I didn’t pay much for that option …; the true value is in Karnes.”

Meanwhile, about Giddings Field, Magnolia reported, “early results show some of the highest production wells to date in the play.” It added that it is an “emerging, high-growth asset with extensive inventory potential and significant development flexibility.”

The leasehold is more than 99% HBP and some 87% operated. The 10,200 boe/d of production is 29% oil and 55% liquids. “Modern high-intensity completions have resulted in a step-change improvement in well performance,” it reported.

EnerVest’s four recent wells averaged 30-day IPs of 1,596 boe/d and 90-day IPs of 1,827 boe/d from roughly 5,000-foot laterals. The production ranged from 31% to 66% oil.

Magnolia estimates at least 1,000 net locations in inventory in the east, if conservatively spaced. It has one rig at work this year and plans two rigs in 2019. In Karnes County, it estimates it has 435 net locations in inventory.

$400 Per Acre

Chazen told Investor of future Giddings results, “My expectations are modest on this. My hope is higher, but my expectations are modest. … I’m going to limit the guys to the cash flow that they produce inside of Giddings, so we’re not taking any money out of the Karnes area and dumping it in here.”

He added, “It is not that I wouldn’t intellectually want to put more money in it. It’s simply a way of ensuring that they are drilling what they think are their best ideas.”

Imperial Capital analyst Irene Haas initiated coverage of Magnolia the morning it began trading, Aug. 1. Its acreage in Giddings Field is held by older, deeper, gassy Buda production. “Magnolia bought the Giddings assets from the bank and, netting out proved reserves, [it[ paid about $400 per acre for the large land position.”

She estimates Magnolia has, if at 500-foot spacing and risking the acreage by 75%, 1,423 net locations for the Eagle Ford. If using 1,500-foot spacing and risking by 75%, she estimates it has 474 net locations for the Chalk.

“In short, we believe that Giddings Field can provide Magnolia with a longer ‘runway’ (than Karnes County).”

She added Giddings Field is “going through a renaissance, in our opinion. Using modern high-intensity completions, [the] Chalk is being ‘rediscovered.’”

Harvest Oil & Gas Corp., which was known pre-restructuring as EV Energy Partners LP, has working interest in all of the properties now owned by Magnolia in the east and a majority of the properties in Karnes County. While an MLP, EVEP’s general partner had been EnerVest.

RELATED: Analysts High On Magnolia Debut

In the east, Harvest has 122,775 net acres in 757,645 gross, primarily for the Chalk. It reported it has upside for Eagle Ford in Lee, Fayette, Washington and Austin counties.

Nick Bobrowski, Harvest CFO, told Investor, “In Giddings Field, we own varied working interests of 15%, 25%, 40%. It averages approximately 20%.”

In the Chalk last fall in Washington County, its 15%-working-interest Neva #2 came on with a 24-hour IP of 2,529 boe, 29% oil and 45% NGL, from a 4,700-foot lateral with 28 stages at 180-foot spacing and 2,800 pounds of proppant per lateral foot. The well cost $8 million.

It had been the first well it drilled in Washington County since 2015, Harvest added.

Workers gear up to spud WildHorse’s Dietz EF 1H well in Burleson County, Texas.

Chalk Math

A WildHorse Chalk well came on in the fourth quarter with an IP-30 of 1,863 boe/d, 32% oil, from a 4,765-foot lateral. In the first quarter, it brought on Chalk wells with 24-hour IPs of between 2,711 boe/d, 67% gas, and 3,416 boe/d, 62% gas, from laterals of about 5,500 feet each.

In some areas, WildHorse has the potential to land wells in both the upper and lower Eagle Ford, Graham said. “We have not put out a map or inventory of uppers and lowers. What we’ve publicly said is we’ve gone out with 400,000 acres of single-target inventory.

“But, yes, we’ve drilled uppers and lowers. We’re not ready to guide at this point on areas that may have two-target potential.”

As the Chalk sits on top of WildHorse’s Eagle Ford, it’s primarily landing in the lower portion to reduce the odds of losing the frack into the Chalk. For the most part, WildHorse has rights to basement; the leasehold is 70% HBP. EUR is 95 boe per lateral foot or 574,000 boe per average lateral.

About 80% of its oil is on pipe; the balance, trucked. It doesn’t have firm contracts on pipe. Graham said, “We try to stay away from that. We don’t need it. We have midstream opportunity that we control exclusively ourselves, and we hope, by the end of the year or next year, we’ll announce some midstream projects we have going.”

About half of its production is basis-hedged at West Text Intermediate (WTI) plus about $3.

Graham emphasized WildHorse’s proximity to Gulf Coast pricing, access to takeaway and oilfield services, the eastern Eagle Ford’s lack of issues with water access, very little produced water and the soon-to-open in-field sand mine.

“There are no operational ‘gotchas’ or none that we can see at this point.”

WildHorse estimates the Chalk, which is about 64% gas, is prospective on 100,000 of its net acres. STRH’s Fitzgerald wrote, “This is largely on the southern end of the acreage where (it) has not been drained by legacy vertical drilling.”

WildHorse is devoting about 10% of its capex budget to it, Graham said. It’s just a matter of the math. “We’re 400,000 acres of Eagle Ford, and we estimate about 100,000 acres for redevelopment of the Chalk.”

Meanwhile, Chalk-well spacing is wider than Eagle Ford well spacing, “so, probably, 10% to 15% of our inventory could be Chalk acreage. We’re actually spending proportionately on the Chalk as to how much acreage we have.”

Graham emphasized that WildHorse is an Eagle Ford oil company. The Chalk can be oily and it can be gassy. “We see anywhere from 70% liquids Chalk wells to 30% liquids Chalk wells.” In the Eagle Ford, though, “everything we drill is 90%-plus liquids.”

Buda-Rose

Other operators are working on the Chalk in the area. “We’ll see how they do,” Graham said. “We’re not too ashamed to copy good techniques from other good operators. We love seeing other good operators in the area, even though part of our business plan is to consolidate and pick people and positions off.”

WildHorse also has rights in most cases to the underlying Buda, Georgetown and Glen Rose. It isn’t drilling that, though; the team will watch how others’ wells work. “Possibly in 2019, we’ll do a few Buda-Georgetown tests, but we’ll do those when the situation is right.”

The results to date of other operators’ work are “across the board,” Graham said.

As for the deepest potential target, Glen Rose, “were oil prices to move significantly higher, then (it) may become more interesting.”

Among those drilling these deeper formations northwest of WildHorse is privately held Kayne Anderson Capital Advisors-backed Treadstone Energy Partners LLC, which STRH’s Fitzgerald said has 18 wells online averaging six-month production of 56,000 boe, 93% oil.

Energy & Exploration Partners LLC (ENXP) had purchased Buda-Rose properties from Treadstone pre-2015 for $715 million. Post-restructuring, ENXP is now known as Pardus Oil & Gas LLC and is focused on the Buda, Woodbine and Eagle Ford.

Also operating in the eastern fairway are GeoSouthern Energy Corp. and Ares Management LP-backed BlackBrush Oil & Gas LP. Four GeoSouthern wells completed in 2017 had IP-30s of between 463 and 765 boe/d with between 57% and 71% oil from laterals averaging 5,948 feet.

One Of The Last Left

Privately held Hawkwood Energy LLC began accumulating leasehold in the eastern Eagle Ford in late 2013 and early 2014. It now holds some 170,000 net, contiguous acres, mostly in Brazos and Burleson counties. The rest is in Leon, Madison and Robertson counties.

Working interest is 85%. It has more than 260 operated wells. Production is some 13,000 boe/d net, 90% oil. It estimates more than 1,000 net additional locations. Secondary oil targets include the Woodbine, Chalk and Buda.

Formed in 2012, Hawkwood is backed by Warburg Pincus and Ontario Teachers’ Pension Plan. Pete Jeffe, senior vice president and chief commercial officer, said, “When we went out to look for assets, we really liked the eastern Eagle Ford. It had—at the time, this was in late 2013, early 2014—very strong existing well economics and rapidly improving results, driven mostly by the completion technology.”

The Hawkwood team, led by chairman and CEO Pat Oenbring, who worked under Chazen at Oxy, also favored the area’s multiple targets. Entry costs were moderate, “and we saw the ability to consolidate and build scale,” Jeffe said.

“And we thought, on a relative basis, it was perhaps undervalued.”

Pre-2015 activity was strong. “Halcón [Resources Corp.] was out here, Apache [Corp.], Anadarko, Clayton Williams. There were numerous private companies, and it’s gone through a big transition,” Jeffe said.

With WildHorse, which was privately held at the time, Hawkwood was pretty much the only large private operator left. Hawkwood picked up Halcón’s position, while WildHorse picked up most of the remaining operators, leaving just EnerVest among large operators and whose South Texas assets Magnolia now owns.

“It went through a big period of transition, but I think it’s coming back and it’s on folks’ radars. It’s on the upswing,” Jeffe said.

And, as Chazen has entered the play, “it’s perhaps a bit more visible again.”

Hawkwood is landing in various parts of the formation. On that, the landing is based on “where are you in the field. We do think that over our Brazos acreage there is the potential down the road for more than one-bench development. But we are not developing it currently in that fashion.” Hawkwood inherited Chalk and Buda wells on its leasehold, but Buda hasn’t been a focus. “There could be potential, but we haven’t looked at it carefully.” As for the Chalk, “there is some increasing activity in this area. It’s gone through a bit of a renaissance.

“We have done sufficient technical evaluation to feel optimistic about certainly a portion of our acreage being prospective for the Chalk, and we’re evaluating right now how to test it or when to drill it.”

With Chalk activity west and south of Hawkwood, “we’re, frankly, trying to learn from other operators,” he said.

Its Eagle Ford is mostly de-risked. It is also actively drilling the semi-conventional Woodbine Sand that is in the northeastern portion of its acreage. “It is high rate of return but more limited in scale compared to the Eagle Ford.”

The Welcomed, Unsolicited Offer

Of Hawkwood’s more than 20 acreage transactions, the largest was from Halcón for $500 million, closing in March of 2017 and including some 81,000 net acres primarily in Burleson and Brazos counties and mostly contiguous to Hawkwood’s existing leasehold. The property came with 170 wells producing primarily from the Eagle Ford.

Picking up Halcón’s portfolio “certainly put us on a new growth trajectory,” Jeffe said. “It doubled our acreage counts. It basically tripled our net production.”

Before the acquisition, Hawkwood was running one rig. “We went to two rigs immediately and are currently running three rigs.”

Hawkwood’s further grown production to about 13,000 net boe/d, about 87% oil, up from about 3,000 boe/d before the Halcón deal. “Upon closing, we went from 3,000 to 9,000, and now we’ve grown to 13,000.”

In addition to tripling production, “it gave us a much larger platform to grow off of.”

Halcón, which had just completed a restructuring, hadn’t offered the property; Hawkwood approached the team. “We knew they hadn’t been putting a lot of capital in the asset in a while,” Jeffe said.

The timing of Hawkwood’s offer “worked out perfectly because, unbeknownst to us, they were thinking about exiting and getting into the Permian. We were able to get a deal done with them, which helped fund their Permian acquisition.”

About 80% of the leasehold is HBP; the percentage is higher in what Hawkwood deems its best areas. Most of the leases include all oil rights, which include the Chalk, Eagle Ford, Woodbine and Buda. Some portions include all depths, including deep gas rights.

Like WildHorse, Hawkwood is using the Gen 3 completion. In the beginning, proppant loading was about 1,000 pounds per lateral foot with higher gel concentrations than now and n with wider-spaced stages.

“We’re using what WildHorse is using [in its Gen 3 wells]—roughly 3,500 pounds a foot of proppant, tighter stage-spacing and significantly less gel. It’s a much cleaner, slickwater design,” Jeffe said.

The results have improved remarkably. “You can go in right next to an existing Gen 1 or Gen 2 and pump a Gen 3 and see a demonstrative uplift in the productivity. It’s also nice to see it work over such a large area.”

In addition, “we’d like to see if we can prove up the concept of refracking old Gen 1 or 2 wells with a Gen 3 design. WildHorse has done this successfully in a number of wells. We’re actually doing it now as we speak. And we plan to progress that program throughout the year.”

The Next 10%

Jeffe estimates Hawkwood will stay with the Gen 3 model, “but there are small tweaks we’re doing and some of it depends on what part of the field we’re in. It’s kind of a never-ending cycle of improvement.

“We continue to tweak the completion to improve the economics either through lower costs or higher well productivity.”

Those ongoing tweaks will present the most drastic improvements going forward, he believes, in “a series of grinding out the next 10% and that’s something we’re always going to be working on until we drill our last well.”

As E&P investors are focused on cash returns and full-cycle economics, Jeffe said the eastern Eagle Ford has some unique advantages in both. For example, the production is oily—typically 85% to 90% in Hawkwood’s wells.

“On an oil-only EUR basis, we compare very favorably to the Permian and certainly to the South Texas Eagle Ford. This is a very oily area.”

Another advantage over the Permian is the realizations. “We’re fewer than 100 miles from Gulf Coast markets. We’re realizing above WTI.”

Also, labor is readily available. “It’s not as competitive for services as in the Permian.” And there is very little produced water, which helps make for a lower LOE.

“All of these things make the economics strong out here and they were, perhaps, overlooked,” Jeffe said. “On top of that, beyond just the strong returns, we see a lot of growth. The Eagle Ford area here has really benefitted from modern completions.

“The core area of the best wells has continued to expand and the results keep getting better. We feel good about both the economics today and the future growth.”

Hawkwood is six years old now and private-equity backed; an exit would seem imminent. Rather, Jeffe said, “we’re focused on execution. Our investors have been aligned with focusing on value and they’re very patient.

“If we can continue to grow and make strong returns, we’ll have a number of options to monetize down the road. We’re always thinking about those things, but our focus is on growing the business through execution.”

Hawkwood has contracts for completion services and sand. “That’s given us a high degree of certainty over costs and availability of services. And it’s insulated us to a significant extent against inflationary pressures. We have the service side of things lined up really well.”

Nearer To The Arch

While Penn Virginia Corp.’s (NASDAQ: PVAC) property sits between what Magnolia has picked up, it’s all still Eagle Ford and Chazen’s entrance bodes well for Eagle Ford operators in general, John Brooks, president and CEO, said.

“I think it speaks volumes that a gentleman of Mr. Chazen’s stature—well respected in the industry and who’s made a lot of money for his investors—has been able to accumulate a large group of capital to pursue opportunities in this part of the Eagle Ford, so I do think that validates that.”

He added, “It remains to be seen what direction they go. The general feeling is they will be acquisitive. We don’t know where and on what scale. In another sense, it means we have another entity to compete with for consolidating properties in the Eagle Ford.”

Also operating east of the San Marcos Arch, Eagle Ford pure-play operator Penn Virginia has seen its stock price more than double this year from about $39 on New Year’s Eve to $84 on Aug. 1. Its leasehold is in Gonzales, Lavaca and DeWitt counties. Devon Energy Corp. (NYSE: DVN) is its partner in some of it.

It announced in late July that it is exploring strategic alternatives. STRH analyst Neal Dingmann wrote that Penn Virginia had done this a year ago, “however, we believe there is much higher probability the company gets sold this time.”

WildHorse is pumping 3,700-plus pounds of proppant per lateral foot in its modern eastern Eagle Ford wells.

Most of Penn Virginia’s roughly 84,000-acre leasehold “has now been geographically delineated with a number of wells outperforming the type curve.” Also, he wrote, the E&P’s oil production is up 115% and its EBITDA is up 215% from a year ago.

“We see the company as an attractive buyout candidate for Eagle Ford players seeking to increase their inventory and production/earnings profile in a proven, highly productive area of the play.”

He added that, despite the more-than-doubled stock price, it was still trading at nearly a two-turn discount to its Eagle Ford peers.

Penn Virginia completed its full transition to an Eagle Ford pure-play in late July, selling its Granite Wash interests in Oklahoma for $6 million. The asset was producing 755 boe/d from 97 gross wells in 7,150 net acres with 2.4 MMboe of proved reserves.

In the Eagle Ford, it’s producing 16,145 boe/d, 78% oil, from 403 gross wells in 83,800 net acres with 82.6 MMboe of proved reserves.

Brooks said the company’s transition to a pure-play beginning in the fall of 2010 was driven by that it was 82% natural gas at the time. “We were focused on finding an oil play and the Eagle Ford checked all the boxes for us. It was not only oil, but had a good mix of gas and gas that is rich, which yields NGL.”

Also, acreage was available. “So it was oily, you could scale it up and, even at that time, the proximity to the Gulf Coast markets gave us confidence we were going to be able to get premium pricing. And the infrastructure was fairly unconstrained and still is.”

In addition, oilfield services on the Gulf Coast are plentiful. “Geologically, commercially, on every standpoint, it checked all the boxes for us.”

First-quarter production was up 28% from the prior quarter. A two-well pad, Southern Hunter-Amber, had an IP-30 of 4,028 boe/d, 90% oil. The first-24-hour IP on its McCreary-Technik three-well pad was 5,425 boe/d, 81% oil; Medina three-well pad, 5,208 boe/d, 63% oil; and Schacherl-Effenberger two-well pad, 3,073 boe/d 88% oil.

Lateral lengths in each of the four pads averaged between 6,050 and 8,100 feet.

Its shallower two-string northern property, known as Area 1, is getting less capital these days as there isn’t as much inventory left there as in its southern, Area 2, leasehold.

“Single-well economics do drive [capital allocation]. And there are other things to take into account. One is the length of lateral you can drill. We think longer lateral wells are the more capital-efficient way to develop the property, whether we’re in Area 1 or 2.”

The deeper three-string Area 2 is higher pressure, thus “a chance to have better well performance. We can drill longer laterals.

“It’s less mature, so there are less offset-well shut-in considerations. And it’s more likely to add reserves, rather than just drilling up proved undeveloped locations.”

Its leasehold is 92% HBP. “The 8% that is not held by production is probably 75% in Area 2.”

Maybe Chalk, Buda

Some leases include rights to basement, but rights are mostly to 100 feet below the base of the deepest completion; thus, Penn Virginia has access to the Glen Rose and everything above it, including Georgetown, Buda, Eagle Ford and Chalk.

It isn’t pursuing the Glen Rose right now. “There are a couple of Buda-Rose wells around us, mostly north and northwest. It’s not a play we’re actively pursuing,” Brooks said.

Instead, besides the primary focus on the Eagle Ford, “we’re paying more attention to activity in the Chalk. There’s legacy Chalk production from ’80s-vintage wells producing in and around our acreage.”

In the middle of Penn Virginia’s area, EOG Resources Inc. (NYSE: EOG) announced its Novosad Unit 10H Chalk well IPed 969 boe/d. “And there’s some other Chalk activity around us developing to the northeast.”

But “we’re focused on the lower Eagle Ford at this point because it really gets down to risk-weighted returns. The Chalk we know is prospective around us because it’s historically produced. But it’s not something at this point that we want to go prospecting for with the drillbit.”

It is including the Chalk and Buda, though, in the 3-D Earth model its G&G team is constructing, incorporating Penn Virginia’s seismic, petrophysical and all the subsurface data it’s collected. The goal is to “better understand the prospectivity of not only the Eagle Ford, Chalk and Buda but the various benches within the Eagle Ford, whether it’s upper or lower.”

If it will pursue another formation, “we’ll let the data drive that decision,” Brooks said. “I don’t think that would change any of our drilling plans in 2018, but it could in 2019.”

Upper, Lower

Penn Virginia has landed in both the upper and lower Eagle Ford a couple of times to date. In addition, the upper part of the lower Eagle Ford—to be less confusing, he offered, the “middle Eagle Ford”—also “looks really good in some parts of our acreage.

“We’ve got a test slated for that. I don’t know if we’ll get it into the 2018 drilling program; it will probably be in the 2019 program for Area 2. We’ve tested it in Area 1 a couple of times, so we know it works.

“The real question, though, is ‘By having that second landing zone, does that ultimately yield you more drilling inventory?’ And secondly, ‘If it doesn’t, are you better off landing it there if you get a better well result than you would otherwise?’

“We have a few questions to answer, and I think we’ll probably wait on the results of the Earth model.”

Additional leasing is ongoing, along with swapping with other operators, “rounding off corners, generating additional inventory by doing that,” Brooks said. The company picked up Hunt Oil Co.’s nearby position earlier this year for $86 million, gaining 9,700 net acres in Area 1 in Gonzales and Lavaca counties.

Penn Virginia already operated 5,700 of those net acres. It also gained 12 MMboe proved, 86% oil, and 1,870 boe/d, 89% oil.

In 2017, it closed on 19,600 net contiguous acres in Lavaca County from Devon Energy for $205 million. That came with 3,000 boe/d, 64% oil.

Penn Virginia expects to drill about 50 net wells this year. “If you assume 80-acre spacing, that’s 4,000 acres we’ll develop so, just to maintain a flat inventory number, we just need to add 4,000 net acres.

“At the end of the first quarter, we already added in excess of 2,500, so it’s not a high hurdle to replace that inventory and, hopefully, grow it as well.”

That’s only counting lower Eagle Ford. “We’re not throwing inventory for upper Eagle Ford and Austin Chalk in there at this point.”

Getting Into The Gen Weeds

In its area, a Gen 3 completion is 2,000 pounds of proppant per lateral foot; Gen 4, 2,500; Gen 5, 3,000. “We can get into the weeds talking about Gen 3, Gen 4 or Gen 5.

“Most people, when we talk about generational labeling, we’re typically talking about how many pounds of proppant and that’s probably a useful guide.”

But “there’s a lot more going on. The fluids are changing in terms of how many barrels per foot you’re putting that sand away with, the rate you’re pumping it at and your perforations. All of those things tend to change as well.

“I don’t think Gen 3 would be the right way to characterize our current completion methodology. It’s probably closer to a Gen 4 with a few Gen 5 tests in Area 2. Those are the two gens I would say we’re more focused on—Gen 4 and Gen 5.”

What about as much as 5,000 pounds per lateral foot? “A Gen 5 of 3,000 pounds is the most intensity we’ve tested. We could go further. We’re open-minded.

“We’re not saying we won’t go beyond 3,000. We have to get an operational rationale for how we would get there in a way that’s economic.”

EURs range from 485,000 to 1.87 million boe, depending on the area and lateral length.

It’s getting LLS pricing and has 80% of its oil on pipe; 20% is trucked. There is additional pipe capacity if operated at a higher pressure, Brooks said.

“The pricing and takeaway capacity are the two biggest headline items,” Brooks said of the Eagle Ford. “The Permian gets a lot of attention—and rightly so for all of its stacked pay—but you’ve got to sell it at the end of the day.

“And this is a fairly mature basin. There aren’t a lot of surprises out there in terms of ‘Is this going to be prospective acreage?’ By virtue of that it’s 92% HBP, we know it’s productive.”

For Penn Virginia, “it’s an execution story at this point.”

The operator’s 2018 goals are all related to capital discipline. “By year-end, we want to grow production by 125%, spend within cash flow and have a leverage ratio of 1.5x—that is, to have a clean balance sheet. It allows us to be opportunistic when opportunities arise.”

Capital One Securities Inc. analysts reported, after Penn Virginia’s “strategic alternatives” announcement, that “the 117% year-to-date gain in [its] shares ranks near the top of our 51-company E&P coverage group.”

In addition, the first-quarter 2018 well results were “outstanding,” and LOE declined to $5.02/boe. “We expect Penn Virginia could make an attractive acquisition target, given it is trading at some $10,000 an acre.”

Exit East

Also an Eagle Ford pure-play, Lonestar Resources has leasehold in 11 counties over the western Eagle Ford (Dimmit, La Salle and Frio), central (Gonzales, Karnes, Fayette, Wilson, DeWitt and Lavaca) and eastern (Brazos and Robertson).

Frank Bracken, CEO, said of the stretch, “Our attitude has always been that we’re not really sure where the opportunities are going to be in terms of additional transactions and the bulk of the way we make money in this business is drilling exceptional wells, not buying the asset itself.

“So we felt like it’s important to have demonstrated drilling and completion competency from one end so that we can create value with confidence wherever the opportunity is available.”

In terms of the transaction activity in the eastern Eagle Ford, what’s he seeing over there? “I would leave that to the experts, but clearly there have been some relatively big transactions. I think, if you were to apply them to Lonestar, they would imply a higher valuation for our stock.

“But I think the big capital influx was really in response to the fact that things just got out of hand in terms of implied leasehold valuations in the Permian. And now, incrementally, with all the well-publicized constraints and the basis blowout, the story’s been easier to sell than it has been in a while.

“I can’t speak for either of those situations but, to some extent, that’s the root of what’s going on.”

Lonestar is getting WTI plus between $3 and $4. When Bracken joined the company in 2012 from his job in investment banking, Lonestar had 1,100 net Eagle Ford acres and the shares were traded in Australia. It’s now traded on Nasdaq.

It had assets in the Bakken, Barnett and Eagle Ford. “The core to my coming was I convinced the large equity holder at the time that the Eagle Ford was going to be a place that we could grow a business very profitably.”

His rationale? In the Eagle Ford’s heyday, 235 rigs were at work, and that still wasn’t enough to hold all the acreage. “There was going to be a secondary market for acreage.”

Also, he anticipated financial failures that Lonestar could take advantage of. And there would be technical failures in industry’s haste to HBP. In addition, the Eagle Ford would get the best price for oil—often the best price for gas as well—and services are plentiful.

“The circumstances that present themselves today are things that don’t surprise us much,” he said.

STRH’s Dingmann initiated coverage of the stock in July with a Buy, adding that management is exploring options for the roughly 15,000 net acres it holds in the eastern Eagle Ford. The operator saw its Wildcat B#1H in Brazos County produce more than 320,000 bbl of oil in 10 months.

But, Dingmann wrote, it reported that “it did not see a line of sight to a major acquisition within the asset (area) and was currently exploring options with its working interest partner.”

‘Now Is The Fun Time’

Bracken said that where Lonestar is spending is based on the return. This year, its spend is almost entirely in La Salle, Karnes and Gonzales counties, west of the Arch.

“At $65 oil, our 2018 program generates us a 78% internal rate of return, and that’s at our third-party engineering projections and, in every case to date, our well performance has exceeded that. So that’s really what’s driving our capital allocation.”

There is Chalk potential in its Karnes leasehold and, in the east, “there’s economic potential there for sure. But the fact of the matter is we acquired our leasehold at very low entry costs and we never depend on anything more than what the lower Eagle Ford will deliver to earn our target returns.

“Everything else is just gravy.”

In the eastern Eagle Ford, “clearly the costs are higher there, but the returns for a lot of companies are adequate to good. When I’m rationing capital to limit my capital expenditures to something that approximates cash flow, the higher IRR areas are always going to win out.

“So, from that standpoint, while the returns are just fine in the east, they’re just higher to the west and central in our area.”

What causes this? “For us, it’s deeper,” Bracken said. “We have to run three strings of pipe [there]. Just things like that. The pressures—we’re in the deeper part of the eastern Eagle Ford at about 10,000-plus feet. So you’re dealing with loss returns in the Chalk; therefore, you’re setting three strings of pipe.

“Higher pressures necessitate higher-strength casing programs and more expensive frack stages, so it’s a combination of all those factors.”

The Magnolia deal is interesting, he said. “Again, I don’t want to speak on others’ behalf, but my understanding of the Magnolia asset is that it’s really kind of a barbell sort of distribution. [Chazen’s] got some really high-quality acreage in the Karnes trough, and it’s a finite leasehold position.

“He has tons of running room in the eastern Eagle Ford in acreage that is largely held by the Chalk, so he’s got a couple of different balls in play.”

Companywide production was 11,140 boe/d in the second quarter, up from 7,700 boe/d in the first quarter. The ramp is “strictly just a matter of engaging for the first time in two years a programmatic drilling program that’s bringing new wells onstream in prolific areas and investing that capital really well.”

While its leasehold gives it rights in most areas to below 100 feet of its Eagle Ford landings, it “doesn’t get us much that we’d be interested in spending capital on.”

SGS analysts’ top picks in mid-summer included only one non-Permian name: Lonestar.

Bracken said, “We fought very hard for our shareholders through a downturn in the industry and in an environment where many management teams just folded up the tent. The quality of our assets and the abilities of our technical process allowed us to weather that storm and actually grow through that downturn.

“Now is the fun time. We have a good price deck, and we’ve got enough capital where we can continue to tie down services. That brings execution certainty. It’s beginning to show up in our financial results. We’re having a lot of fun now.”

Nissa Darbonne can be reached at ndarbonne@hartenergy.com.