Some new words have crept into the lexicon of private E&Ps courtesy of the current recession in oil and gas prices. The standard buy-and-flip strategy, or more recently, buy-develop-flip/IPO dogma, now includes a “survive” phase before monetization.

Ben Burke, senior geologist with Fifth Creek Energy LLC, discussed these shifts in strategy and more while speaking on a panel of private operators at the recent DUG Rockies Conference & Exhibition held in Denver, Colorado. Joining him in a discussion of how private players are negotiating the downturn were Permian player Centennial Resource Development LLC and Powder River Basin-focused Peak Resources LLC. The latter two have hobbled drilling until prices improve, while Fifth Creek is an earlier-stage company still hunting for assets. Also presenting at the conference was private operator Laramie Energy LLC, which has remained active, albeit at a slower pace.

Wolfcamp A—for now

Centennial has built a 41,000-net-acre position in the oil core of the Southern Delaware Basin since it was formed in 2013 with backing from NGP. CEO Ward Polzin said results to date have been “among the best initial production results and EURs per lateral foot in the Southern Delaware” and hold their own with IRRs achieved in the Midland Basin. The company will ultimately chase the full line-up of stacked formations available in the Delaware, including Upper and Lower Wolfcamp A, Wolfcamp B, Wolfcamp C and Third Bone Spring. But for now, having cut its four-rig program to one, its efforts are focused on the Wolfcamp A.

Centennial has expanded its reserves by 30% to some 32 million barrels of oil equivalent (boe) of proved reserves, 71% oil. When prices rebound, it expects to uncover further upside in the Second and Third Bone Spring shales.

Held flat through 2015 on a reduced drilling program, the company’s production is 7,000 boe/d. Centennial has drilled 35 horizontal wells to date, in addition to the 20-some in place at the time it bought the assets from Atlantic Exploration LLC in mid-2014. It’s whittled drilling and completion costs to about $5.8 million (including facilities and proppant) from $12 million.

Average cumulative well production has increased 35% since Centennial took over the assets. It uses a hybrid frack of slickwater and gel with single-section laterals of about 4,500 feet, 23 stages and 200 feet per stage. Polzin noted that the company has kept its base frack “pretty much the same” since 2014, so improvements have come via tweaks.

“It’s amazing how the combination of small things that we’re forced to do now add up to significant changes,” he said. “High-intensity fracks will be the next step. Our last 12 Reeves County wells significantly outperformed the type curve.”

Overall, drilling time has been reduced from 45 days to about 22 days. Drilling and completion capex has declined by about 47% since 2014, even as the average lateral length has increased by about 13%.

When commodity prices are in the tank, hardly anything beats optionality. Centennial has few drilling obligations, so it can be flexible with its capital spend. It has converted field personnel from contractors to employees to increase the emphasis on reducing costs and that “we’re all in this together,” Polzin said.

He noted that the downturn has lasted some 18 months, and he thinks “we’ve got another year to go” before commodity prices improve significantly. “You have to play defense—throw the 10-yard pass,” he said.

As a private-equity backed company, he noted, “You have to accept that you’re going to be here for longer, and the returns are going to be a little lower.”

A fourth Peak

Jack Vaughn’s Durango, Colorado-based Peak Exploration & Production LLC is on its fourth iteration, this time in the Powder River Basin. Previous Peak entities have worked in the San Juan Basin, the Granite Wash, the Texas Panhandle, the Barnett Shale and most recently, the Williston Basin.

Peak has assembled some 43,000 acres, and it drilled its first well on the Powder River acreage in 2012. Like the Permian, the Powder offers plenty of stacked pay, from Frontier through Turner, Parkman, Niobrara, Shannon and Sussex. Peak’s team also sees upside in the Muddy and Dakota formations. Its land, mainly in the middle of the basin, has a fairly large component of federal and state holdings, but “we understand the regulatory environment and know how to manage through it,” Vaughn said.

To date the company has drilled more than 60 horizontal wells, and like Centennial, is holding production flat at 8,000 to 9,000 boe/d. It is working conventional zones while keeping an eye on the resource play potential of the Niobrara. Drilling in the Powder’s overpressured zones can be challenging and costly, much like in the Southern Delaware Basin. About 8% of the revenue stream is gas and NGLs, so Wyoming’s strict anti-flaring regulations require that the company have infrastructure in place to handle associated gas.

Peak laid down its last rig—it had been running three—in January, but Vaughn said he expects to start one back up in the third or fourth quarter of this year.

Cost cutting is the focus today. “We’ve done a lot of science,” Vaughn said, “and since 2013 our average well cost has been reduced by about 40%.” The company is careful about how it monitors flowbacks on its overpressured wells to protect long-term EURs. “You don’t want to get too aggressive,” he added.

With minimal debt requirements, Peak is weathering today’s tough market while keeping in mind the rate-of-return requirements of its private equity backers, principally Yorktown Energy Partners. It plans to operate within cash flow and continue to lower its G&A costs.

Liberty’s frack design

Liberty Resources II LLC’s CEO Chris Wright spoke separately at the DUG Rockies event on a panel about breakeven costs. Frack design matters, he said.

Wright believes the oil and gas industry as a whole underinvests in well stimulations, thus leaving significant reserves—and money—underground.

“Our belief on fracks is you’ve got to touch a lot of rock as cheaply as possible,” he said. “In tight rocks, it’s about maximizing your contact area with the pay rock. We build intense plumbing underground—our frack intensity has been high.”

A self-proclaimed “bunch of tech nerds that think there is a lot of upside in unconventional production,” the Denver-based company, with backing from Riverstone Holdings LLC, formed its second iteration in 2013 and acquired 53,000 net acres in the Williston Basin. Liberty I also operated in the Bakken Shale before selling to Kodiak Oil & Gas for $680 million the same year.

“Our overriding goal is to minimize the cost of producing each barrel and to maximize the reserves we own,” he said.

In the boom days, companies typically truncated frack designs to keep well costs down, Wright said, but “that is not the way to minimize cost per barrel. If you understimulate the rock, you get lower EURs, and your cost per barrel is higher.”

Rather, increasing the hydraulic fracture via more contact area and conductivity to the wellbore raises the EUR.

“Investing more money upfront is scarier, but if your production is much greater and your cost per barrel is lower, then it’s worth it. The proof is in the production.”

Wright cited a test that raised well costs by 2% due to increased sand loading but resulted in a 10% uplift in EUR. “How much do I have to increase my well cost to increase my EUR by 10%?” he asked. “If it costs less than 10%, it’s a positive investment.”

On the other side of the equation, Wright said operators should avoid the “bull in a china shop” behavior: increasing frack intensity past the point of diminishing returns. “We raised our EUR as much as we could without raising the cost of producing a barrel,” he said.

Liberty uses “big data” empirical analysis to better its frack designs. “You’re not just learning from your own wells and experiences; you’re learning from your neighbors as well.”

The company also minimizes cost per barrel by using centralized production facilities and infrastructure.

Liberty builds a drilling spacing unit around 10 to 12 wells, reducing the total number of treaters, separators and tanks needed to produce the wells.

Underground infrastructure ties the wells together. Liberty buries a gas gathering line, an oil gathering line and a fuel gas delivery line in one trench while a produced water line, a frack water line and a fresh water line flow through another trench, resulting in “significant cost reduction” of facilities and completion services.

If increasing frack intensity sounds so obvious, why isn’t everyone doing it? Because the simplest economic metric to measure is well cost, he said, which is misleading.

“My view is we don’t sell wells, we sell oil, so we should laser focus on dollar per barrel.”

Piceance Basin contrarian

The Piceance Basin in western Colorado may be out of favor to some due to gas prices, but its trillions of cubic feet remaining in stacked pay zones up to 4,000 feet thick ensure its importance to U.S. gas supply once the price of natural gas recovers.

“This is a resource that will be very important to the country when prices turn,” Bob Boswell, chairman and CEO of privately held Laramie Energy II LLC, said during an operator spotlight on Rockies gas at the conference.

Laramie is focused 100% on the Piceance, where the Denver company is developing basin-centered tight gas sands, seeking pay in the Williams Fork and the underlying, overpressured Mancos Shale. It upped the ante in the basin during the downturn in December 2015 when it acquired $157.5 million of Piceance assets, increasing the company’s production to 140 MMcfe/d.

hen it’s a bad time to drill, it’s a good time to buy,” Boswell said, adding that this is the sixth downturn, and one of the worst, he has seen during his career. He’s done it before—in 2012 he bought assets out of the Delta Petroleum bank­ruptcy by issuing new equity to the Delta bondholders.

Boswell plans further acquisitions to consolidate acreage and gas gathering assets in the basin and may restart completions in the third quarter, depending on gas prices. He dropped the company’s one drilling rig in December, but may pick up one rig in first-quarter 2017 if gas reaches a steady $3/MMBtu.

This time around, Boswell said, his strategy to build a company is different. The first iteration of Laramie employed a “prove and move” strategy during the advent of unconventional plays. The company acquired significant Piceance Basin acreage, and then completed wells with the notion to sell to a larger entity. Sure enough, it sold to Plains E&P for $1.1 billion in May 2007. Boswell restarted a month later with Laramie II, backed by private equity from EnCap Investments and Avista Capital, among others. Today he plans a more measured approach toward full-scale development and growth, he said.

Laramie has 12,000 drillable vertical Mesaverde and 2,400 horizontal Mancos locations based on 160-acre spacing units. Boswell likes the Piceance for the potential of the 4,000-foot Mancos Shale and the 3,000-foot Williams Fork.

Production in the Piceance Basin peaked at 1.6 Bcf/d and now makes up about 20% of total Rockies output. More than 12,000 wells have been drilled to date, giving producers like Laramie plenty of data to chew on. At the peak in 2008 there were 90 rigs working; today there are only two.

Wells’ average EURs have increased to 1.5 to 2 Bcf each from 1.2 Bcf as companies have climbed the learning curve and improved their frack techniques. Capital costs have come down to about $1 million per well. Some 16 to 22 wells can be drilled on five-acre pads.

“Unlike in the eastern U.S. gas plays, the Piceance has unconstrained pipeline capacity, and the Rockies basis is strengthening,” Boswell said.

Excitement about the basin has been boosted by the emerging Mancos Niobrara Shale.

“We think it is going to be a very large resource base once the price is right,” Boswell said. “We haven’t broken the cost code yet, but we will. In the Mancos, we’ve drilled six verticals, and we’re getting 4 to 4.5 Bcf of dry gas. There are little to no NGLs, so these are a bit less economic,” he said.

A Fifth Creek

Still in the early stages is Fifth Creek Energy LLC, the fifth iteration by the founders of Bonanza Creek Energy, Mike Starzer and Pat Graham, who took Bonanza public with great success in 2011. Fifth Creek was founded in late 2014 and is currently evaluating deals for its first acquisition. Ben Burke, PhD, senior geologist, discussed the company’s strategy at DUG Rockies and what he’s seen evolving in deal flow and structure. Fifth Creek’s main financial sponsor is NGP Energy Capital Management, with support from BNP Paribas, Holmes Creek and Wells Fargo.

Fifth Creek’s target size for an acquisition is $500 million to $1.5 billion, and it’s seeking PDP reserves as well as growth potential. In terms of deal structure, it’s open to cash, cash and equity, JVs and earning participations, special purpose entities, seller-retained overrides and net profits interests and operating partnerships.

How will the A&D market shake out for the many management teams looking for a foothold across the U.S.? The competition is fierce. Burke figures there are 400-plus teams and 30-plus private capital providers representing some $30 billion focused on the E&P space.

Since 2008, he noted, independents’ business strategies have evolved. In 2008, during the initial shale frenzy, the process was to buy and flip; in 2010, buy, drill a few and flip; in 2012, buy, develop and flip; in 2013-2014, buy, develop and IPO. In the past year, however, the model has lengthened, to buy, develop, survive, optimize—wait on a commodity rebound—and monetize.

Holding for longer is the name of the game.

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