Green Shoots In Greeley

Driving along the rural roads around Greeley, Colorado, the early, lush growth of rain-soaked fields surrounds pumpjacks and storage tanks. For some E&Ps, the economic landscape of the Niobrara remains similarly familiar, even in the wake of the jarring drop in crude oil. For others, a period of lying fallow in response to the downturn is drawing to an end, with green shoots of an activity upturn beginning to emerge.

Still, when the rig count in a play is cut in half, as it has been in the Denver-Julesburg Basin’s Niobrara play, no one is spared. The differences in E&Ps’ corporate positioning—less noticeable at higher crude prices—are magnified when crude is $55 to $65, its recent range. E&Ps have adjusted to the lower price environment using a variety of strategies. Some are sharpening their focus on mid-length and extended-reach lateral (XRL) wells; others are leveraging returns by maximizing use of existing infrastructure.

In the Denver-Julesburg Basin, E&Ps also have benefited from the re-set in oilfield service costs as well as from their own initiatives to improve drilling efficiencies, and they are poised to gain from a long-overdue, significant expansion in infrastructure. Prior to the sharp falloff in rig activity, processing and takeaway from the basin had lagged industry needs, with E&Ps often facing major line pressure issues. This should be largely alleviated by two major pipeline startups of incremental capacity that were scheduled to be completed by midyear.

And there are signs of a pickup in activity. At press time, commodities appeared to be stabilizing even if at levels substantially lower than a year or two ago. Two E&Ps drilling the Niobrara have indicated they are adding rigs this year in the basin, while a third is pressing forward with a plan to add an additional rig in each of the next two years.

Anadarko Corp. vice president for Wattenberg operations Craig Walters said the efficiencies and cost savings achieved in the basin over the past six months are “a gamechanger that we don’t expect to go away.”

A self-funding asset

Relative to some of its peers operating in the basin’s Wattenberg Field, Anadarko Petroleum Corp. has perhaps had to make fewer changes to adjust to lower crude prices. It has traditionally spent within cash flow, and this year planned to reduce “short cycle” onshore rig activity by about 40%. Citing its “resilient economics,” the company set its initial capital budget for Wattenberg at $1.8 billion, down about 22% from the prior year, escaping a deeper cut.

“We’re about preserving value, and being in a position to grow that asset in the future,” said Craig Walters, Anadarko’s vice president of operations for Wattenberg, of the belt-tightening this year.

Helped by a consolidated acreage position in the core of the field and the company’s mineral ownership advantage stemming from the Union Pacific land grant, Wattenberg is prized for its ability to be a steady free-cash-flow generator.

“It truly is a world-class asset,” said Walters. “It’s a standalone, self-funding entity, even as we invest $1.8 billion into it this year. And it self-funded last year, when we invested about $2.3 billion.”

This is not to imply current conditions are not challenging. Last year, Anadarko was citing rates of returns of more than 100% for its Wattenberg wells. At crude prices prevailing in this year’s second quarter, the before-tax internal rates of return on the same type wells were a much lower—but still respectable—45% to 50% for a mix of land grant and non-land grant wells, according to Anadarko.

Its mineral ownership advantage from the land grant, in which it retains a royalty normally paid to a third party, remains a significant contributor to the wells’ net present value (NPV). At strip prices at press time for oil of around $61.30/bbl, a Wattenberg well costing $3.4 million with an estimated ultimate recovery (EUR) of 350,000 barrels of oil equivalent (boe) is estimated to have a before-tax NPV of $3.7 million. Of this, Anadarko attributes some $1.2 million to its mineral ownership. The recent $1.2 million mineral advantage compares to $2.2 million last year, when a similar 350,000 boe well, costing $4 million, was estimated to have a NPV of $7 million. But that was when the underlying assumption was for a well to lock into a revenue stream based on a constant Nymex price of $90/bbl. Those were the days!

The Wattenberg budget provides for an eight-rig program in 2015, down from 12 to 14 rigs a year earlier. The company’s plan to drill 300 wells despite the reduction reflects its efficiency gains and ability to do more with less. The wells will comprise a mix of roughly 60% standard-reach laterals (SRLs), typically with lateral lengths of 4,200 feet or more, and 20% apiece of mid-length and XRLs, with lengths of 7,500 feet and 9,400 to 9,500 feet, respectively.

Has Anadarko gravitated toward the use of mostly longer laterals?

“We don’t see huge variability in rates of return across the spectrum,” said Walters. “We’ve been very successful with mid- and long laterals. The mid-laterals are probably our sweet spot. What usually drives us to drill the XRLs is surface considerations. With the XRLs, you can have a smaller surface footprint.”

By working with suppliers and improving drilling efficiencies, Anadarko has lowered costs to drill a typical XRL well to $3.4 million, down from $4 million last year. Much of the savings are viewed as permanent, coming from “efficiencies that we’ve been able to drive into the system over the last six months,” said Walters. “That’s a game-changer that we don’t expect to go away.”

Anadarko’s development of its midstream infrastructure “in lock-step” with its upstream operations has provided “a competitive advantage” to the company, Walters said, leaving very few of its volumes dependent on third-party processing or takeaway. This is being reinforced with the commissioning of the 300 million cubic foot per day (MMcf/d) Lancaster II plant early in the third quarter, plus an incremental 90 MMcf/d of compression that was added earlier this year.

In terms of new horizons, Anadarko is one of several companies, including Noble Energy Inc. and Synergy Resources Corp., that have tested for the deeper Greenhorn Formation underlying much of Wattenberg. Wall Street reports have suggested encouraging results from at least one of the Anadarko wells, but little other color has emerged.

“We do have three Greenhorn wells under our belt,” said Walters, adding simply, “It’s still early in the evaluation of that particular target.”

What new challenges lie ahead—beyond an inventory already totaling some 4,000 horizontal drilling locations?

“What I get excited about,” said Walters, “is all the improvements and efficiencies that we’re going to be able to continue enhancing and applying to the Niobrara and Codell development in those 4,000 additional locations.”

Hedged and ready for growth

With a strong balance sheet and a formidable hedging program, Denver-based PDC Energy Inc. has barely missed a beat in transitioning to a lower oil price reality. In February of this year, the company maintained its prior production guidance for 2015 even as it cut its capex estimate by 15%. Then, at its April analyst day meeting, PDC rolled out three-year production targets which, under its “base case,” called for an expected 31% to 35% compound annual growth through 2017.

Coming into 2015 with debt-to EBITDA of less than 2x, coupled with crude hedges covering approximately 85% of current year production at more than $88/bbl, PDC was in a favorable position. This allowed the company to keep running a five-rig program in 2015, with plans to add a sixth and seventh rig in Wattenberg in 2016 and 2017, according to its base-case scenario at the analyst day. For 2015, PDC projects drilling 119 wells, with 109 wells turned to sales.

How closely is PDC tracking what would have been—if not for the collapse in crude—its earlier growth trajectory?

“From a rig count perspective, we’re one rig behind,” said Bart Brookman, CEO. “But we’ve had some really good improvements in drilling efficiency. A year ago, we thought we’d get to where we are today with more rigs, and we’re actually getting there with more efficient operations. Overall, we’re not that far from where we thought we’d be with six rigs, but we got there with five.”

One benefit of the downturn: It has allowed PDC to pick up more efficient rigs being dropped by competitors, said Scott Reasoner, PDC’s senior vice president of operations. “We originally had two ADR rigs, also called flex rigs, at the start of the year. And now all five rigs are Ensign ADR rigs, capable of drilling at approximately 200 lateral feet per hour,” he noted.

Production momentum was building this summer for PDC Energy, when the company expected to have the “most aggressive turn-in-line schedule” in its history, according to Bart Brookman, CEO.

Production momentum was building this summer, when the company expects to have the “most aggressive turn-in-line schedule in the history of PDC,” according to Brookman. The company expects to have 40 to 45 Wattenberg wells connected to sales in the second quarter—ideally, in sync with the Lucerne II plant owned by DCP Midstream starting up—with the full impact of the new wells being felt in the third quarter.

PDC has achieved an uplift in type curves in its three main operational areas (Inner Core, Middle Core and Outer Core), resulting mainly from increased frack-stage density. Well designs now employ fewer than 200 feet between frack stages, down from 250 feet previously, raising the stage count to 20 from 16. In line with the 25% jump in stage count, sand and fluid volumes have also gone up by 25%.

As a result, well performance is up nearly 10% even as well costs have come down. PDC estimates that the cost of a SRL well with a 4,200-foot lateral has fallen to $3.4 million, down almost 20% from the prior $4.2 million, thanks to the combination of oilfield cost savings and improved drilling efficiencies.

The more intensive completion designs have resulted in EURs in the Inner Core Niobrara, which PDC says is a “focus area for 2015 development,” being upgraded to 625,000 boe from 580,000 boe previously. For the Middle and Outer Core Niobrara areas, new EURs are 440,000 boe and 310,000 boe, up from 400,000 boe and 285,000 boe, respectively.

Similarly, the two Codell type curves have been upgraded. In the Inner/Middle Core Codell, EURs have been upgraded to 440,000 boe from 400,000 boe previously, while EURs in the Outer Core have moved up to 310,000 boe from 285,000.

Recently, PDC has also shifted to drilling “midrange” XRLs in its Middle Core area, where industry data show best per-foot performance coming from laterals of 6,000 to 8,000 feet in length. The company plans to turn to sales in 2015 about 47 such wells, costing $4.4 million apiece, the majority of which—34—are on the adjacent Chesnut and Churchill pads.

PDC estimates it currently has 2,200 2P locations in the Niobrara, of which its Middle Core area, with 1,400 locations, accounts for just under two-thirds. In its Inner Core area, with IRRs estimated at 76% at a $60/bbl Nymex price held flat, there are 100 remaining locations. For the Codell, IRRs are estimated at 40% in the Inner/Middle Core area, where PDC has 372 remaining 2P locations.

Apart from acreage swaps, are moves to further enhance PDC’s position in the Wattenberg under consideration?

PDC’s base case is 20 wells per section, but it is also testing 22 and 26 wells per section. “Almost every pad has a little bit of customization to it,” said PDC’s CEO, Bart Brookman.

“We’re pretty content with our 2,500 to 3,000 locations,” said Brookman. “Right now I think the market views us as having strong economics that are very repeatable; it doesn’t want us to do a deal that adds lesser-quality acreage. The only thing we’d consider in Wattenberg would have to be core.”

Company reset

Like PDC, Synergy Resources Corp. also maintained a strong balance sheet going into the downturn, a pattern characteristic of its life as a public E&P. As a result, the Platteville, Colorado-based company is well-positioned to continue growing organically, through tactical acquisitions, or via a combination of both.

In terms of organic growth, Synergy announced in June that it was preparing to add a second rig in September. The announcement came as the company unveiled a capex program for the coming fiscal year, ending Aug. 31, 2016, of $250- to $300 million. The budget could accommodate an expansion of funds towards its Greenhorn Formation prospect in the Northeast Wattenberg Extension area, if warranted, it noted.

Regarding deal flow, Synergy co-CEO Ed Holloway said he has continued to see “bigger rather than smaller deals.” However, the pace of transactions has slowed as E&Ps’ access to capital markets has improved, and as commercial banks have delayed decisions on more problematic borrowing base redeterminations until the fall. “The banks have kicked the can down the road a bit,” he said.

Recently, Lynn Peterson, former CEO of Kodiak Oil and Gas Corp., joined Synergy’s executive team as president. Peterson grew Kodiak to a multibillion-dollar E&P in the Bakken, selling it to Whiting Corp. in mid-2014. He will help evaluate asset acquisitions and growth opportunities in Wattenberg and the Northeast Extension area, according to the company.

“I think you’ll see him maintain a very conservative approach to debt leverage,” said Holloway.

“Our goal is to reset the company so it can survive in a $45 to $65 oil environment and yet have returns like when oil was approaching $100,” said Synergy Resources Corp. co-CEO Ed Holloway.

Concerning the Greenhorn prospect, Holloway said he was “cautiously optimistic.” Drilling of the Conrad well had gone “extremely well with no surprises,” he said, “and from all our science, the formation should give up production. But the key will be the frack.” Halliburton Co., which Wall Street sources say completed the three wells drilled by Anadarko, is reviewing test results with Synergy to determine the optimum completion.

Completion operations were due to begin by mid-July, with results expected to be released in August or September. Holloway acknowledged that it would likely take several wells to fully assess the Greenhorn’s potential. If the play is successful, E&Ps standing to benefit most—other than Synergy—would be Bill Barrett Corp. and Bonanza Creek Energy, as well as PDC Energy.

In the meantime, Synergy expects to bring a surge of new production online from 40 gross wells by August 31. This includes output from four multiwell pads serving both Niobara and Codell producers. The 13-well Kiehn/Weiss pad, comprising six Codell wells, six Niobara C wells and Synergy’s first well drilled to the Niobrara A bench, is already in production.

Completion operations were underway at the eight-well Geiss pad, where production was due to begin in July. Drilling is complete at the Cannon pad, comprising six Codell wells and five Niobrara C wells. Drilling and completion costs are expected to come in between $3.1 million and $3.6 million per well, with the potential for several to be $3 million or less. Production was due to begin in late July. Completion plans at the eight-well Weideman pad were being finalized.

Bonanza Creek Energy CEO Richard Carty says the extension of Wattenberg Field has moved from exploration to appraisal and early production, and now is transitioning to full field development.

Under its 2016 capital program, Synergy plans to drill a greater percentage of mid-length and XRL wells. To date, it has drilled fewer than a dozen mid-length and XRL wells.

For SRL wells, it offers a wide range of EURs: 275,000 to 400,000 boe. Although EURs are important, Holloway said Synergy “is less EUR-driven and more rate of return-driven.” The company targets a payback period of three years or less. “Ideally, we want to get our money back in two years or less,” he added.

“The whole industry is in a reset,” continued Holloway. “Our goal is to reset the company so it can survive in a $45 to $65 oil environment and yet have returns like when oil was approaching $100. Can we get there? I don’t know. That’s why we are so fixated on costs.”

Development mode

At Bonanza Creek Energy, CEO Richard Carty has in place a “disciplined” plan for deploying company capital, focusing as much on leveraging existing infrastructure in the current downturn as on maximizing individual well economics through lower well costs. Both are important factors in maximizing returns in the Niobrara, which he now sees “transitioning to full field development” from an exploration story sparked into life by horizontal drilling.

“The subsurface is now largely understood and delineated with respect to our ability to drill horizontal wells in multiple, oil-weighted pay horizons,” said Carty, who took over the CEO position this past November. “With the large number of wells on production, and the amount of capital that industry has invested in the field, the extension of Wattenberg Field has gone from an exploration field to an appraisal and early production field, and now it’s transitioning to full field development.”

Bonanza Creek currently holds roughly 97,000 gross (70,000 net) acres in Wattenberg. Of this, some 34,600 net acres were acquired from DJ Resources LLC, in a transaction closing in July of last year. The acquisition featured two asset positions: a northern block of 25,700 net acres, directly offsetting Noble Energy’s Wells Ranch development, and a southern block of 8,900 net acres.

The northern block is made up of largely contiguous acreage, with the southern acreage being more “checkerboard” in nature. With its legacy acreage also highly contiguous, Bonanza Creek estimates as much as 70% to 75% of its overall acreage is suited for development using XRL, giving the company a long-term advantage.

“Probably the biggest advantage of our acreage position is the contiguous nature of our legacy acreage and our northern acreage position, and the fact we can exploit XRL drilling along the infrastructure and facilities-type work,” noted Tony Buchanon, Bonanza Creek’s COO.

In the near term, however, the drive to optimize the use of existing infrastructure—located largely in legacy areas—has taken priority. This has led to a mix of lateral lengths, with XRL drilling accounting for only 29% of the 2015 capex budget. Other things being equal, an XRL program offers the best returns, the company noted. But, if SRL drilling can be tied into existing infrastructure, then the greater infrastructure optimization tips the balance in favor of drilling SRL wells.

“Leveraging that fixed asset infrastructure and developing those locations in an integrated way drives long-term economics,” emphasized Carty.

Moreover, ample scope exists for further optimization of infrastructure in legacy areas, which claim the lion’s share of the budget. “We have about 1,200 net 3P locations in that legacy area, and by the end of this year we’ll have drilled less than 350, so that allows you to continue leveraging up the existing infrastructure going forward,” said Buchanon.

In total, Bonanza Creek estimates it has a 3P inventory of about 2,000 net locations. This year it plans to drill some 88 gross/77 net wells, down from 114 gross/109 net wells last year, using a two-rig program in Wattenberg. Prior to the crash in crude, and its decision to cut back to two rigs, Bonanza Creek was planning for six rigs, including two rigs in the northern block that abuts Wells Ranch.

Not surprisingly, there is an emphasis on larger pads, with the average pad comprising four to six wells this year as compared to two to three wells in 2014. Of particular note is a “Super Section” pad and centralized facilities, which initially accommodated production from 14 wells, but now handles production from a total of 21 wells. During the remainder of 2015, an additional 12 wells drilled on nearby sections will ultimately tie into the surface facilities located on the Super Section pad.

“Our contiguous leasehold allows us to do bigger pads in a tougher environment and then tie in multiple pads to existing centralized facilities,” said Buchanon.

In terms of the basin’s processing capacity, the commissioning of several new plants means Bonanza Creek “is going to be in much better shape than we’ve ever been,” according to Buchanon. “It looks like DCP Midstream has leapt ahead of operators’ needs for a while and put us in a pretty good position for the next couple of years.”

Buchanon noted the projected midyear startup of the Lucerne II plant, with a capacity of 200 MMcf/d, would double the combined capacity of the O’Conner and Lucerne I plants. In addition, with a capacity of 45 MMcf/d, the 70 Ranch compressor station is “ready to run” as soon as Lucerne II starts up, he said, and the Sullivan compressor station has been expanded to 40 MMcf/d from 10 MMcf/d earlier.

Midstream companies have significant crude oil takeaway and gas processing and compression initiatives underway in Colorado’s Weld County to keep capacity ahead of operators’ needs.

As for targeting the Greenhorn, Bonanza Creek has no plans for a test at present. However, the formation underlies its acreage, and tests have been made in the surrounding areas by Anadarko to the south and west, by Noble Energy to the north, in the East Pony area, and by Synergy to the east.

If it works, “the nice thing about the Greenhorn is you can come back and drill those wells using the existing infrastructure you have,” commented Buchanon. “It’s deep enough that it shouldn’t interfere with your existing operations. You won’t frack into existing wells; it’s just deep enough to get past that.”

If it works, “the nice thing about the Greenhorn is you can come back and drill those wells using the existing infrastructure you have,” said Tony Buchanon, Bonanza Creek Energy Inc. COO.

Adding a rig

Based on neighboring E&Ps’ and the company’s own improving well results, it may come as no surprise that Bill Barrett is increasingly optimistic about the use of XRL wells. The company has just under 50,000 net acres in Northeast Wattenberg and in July—reflecting the confidence that has grown from its early XRL well results—Barrett added a second rig in the play.

Because its acreage position was “untouched from a vertical development standpoint,” Barrett believes that this has created an acreage advantage relative to its D-J peers and that 80% of its “highly concentrated” position will be suitable for development using XRLs. The company was encouraged by results from the 24 XRL wells it drilled last year, and this year it expects to drill 35 to 40 operated XRL wells under a 2015 total company capex budget that has been revised more than 25% higher to $320- to $350 million to reflect the additional drilling rig.

Describing the Northeast Wattenberg as its “growth driver,” Barrett is forecasting a 60% jump in the play’s production in 2015, followed by a 25% increase in output in 2016. The higher level of production next year assumes an annualized capex run-rate of $225- to $275 million for the company, based on a continued two-rig, 40-XRL well program in the play, according to Barrett.

Barrett Resources CEO Scot Woodall said the company will have a competitive advantage based on the fact that “80% of our acreage can be developed with XRL wells on a 1,280-acre spacing unit.”

“Beginning in mid-2014, we started drilling almost exclusively these XRLs. And when the results came out six months later, they were great,” recalled Scot Woodall, CEO of Barrett. “The fact that 80% of our acreage can be developed with XRL wells on a 1,280-acre spacing unit is going to be a distinguishing factor going forward. We think that’s a huge competitive advantage.”

Woodall acknowledged the intelligence Barrett gained from the production history of Noble Energy’s XRL wells in the adjacent Wells Ranch area. “We turned on a dime,” he said, and re-permitted the locations to accommodate XRL wells. “It was obvious that that was the most economic way to develop the field.”

Barrett’s evolution to its current drilling and completion design has comprised several steps. From a 4,000-foot lateral two years ago, with 15 to 18 stages, Barrett today typically uses a 9,500-foot lateral, with 55 frack stages. Sliding sleeves have given way to plug-and-perf technology, and proppant loads have jumped from 600 to 800 pounds of sand per lateral foot to approximately 1,000 pounds per foot.

Another equally important operation enhancement is the use of a controlled gas flowback. By suppressing gas production during the first few months of production, the reservoir pressure maintenance allows oil production to increase to an optimum “peak month rate.” Although there is a delay in reaching the peak month rate, subsequent months produce at shallower decline rates, increasing well EURs and thereby economic value, according to Barrett.

These enhanced operations of controlled gas flowback, coupled with the shift from sliding sleeves, with 40 frack stages, to plug-and-perf technology, with 55 frack stages, increased the peak 30-day average rate from 550 boe/d to approximately 650 boe/d. The 60-day average production rate improved from 453 boe/d to 600 boe/d, exhibiting a much shallower initial decline, Barrett said.

Barrett calculates an IRR of 39% for its XRLs, assuming drilling and completion costs of $6.25 million, down from $8.25 million in 2014; a two-stream EUR of 700,000 boe; and Nymex WTI oil and natural gas prices of $65/bbl and $3.50/Mcf, respectively. The IRR drops to 34% if the commodity price assumptions are lowered to $60/bbl and $3.25/Mcf.

The company has an inventory of roughly 2,000 3P locations, comprised mainly of Niobrara B and C locations, plus some Codell and Niobrara A locations.

Barrett has a strong commodity hedge book, with 90% of remaining 2015 production hedged at average prices of $90.01/bbl and $4.13/Mcf, and approaching half its 2016 output at $80.81/bbl and $4.10/Mcf.

Bayswater Exploration & Production LLC’s president Steve Struna said the private company’s growth will be mainly organic over the next couple of years, with two rigs drilling in Wattenberg.

In June, the company announced an “at the market” equity offering to raise up to $100 million over a period of time, which will bolster a liquidity position of some $500 million, including $149 million in cash at March 31, 2015, and an undrawn borrowing base of $375 million. The company has indicated its cash flow outspend in 2015 will not exceed cash on hand.

Taking chips off the table

Led by president Steve Struna, Bayswater Exploration & Production LLC is a Denver-based, privately owned E&P that has successfully made a living for itself working the Niobrara and Codell horizons in Wattenberg. The company has grown both organically and through a series of acquisitions, starting in 2010, and hasn’t hesitated to take chips off the table when the time has been right.

The early growth of the company saw Bayswater build a position of over 30,000 acres in the D-J Basin, where it operated some 400 vertical wells. The company subsequently pared back its position by roughly half, closing two asset sales involving 13,000 net acres and related production in the second half of last year. The two transactions took in over $200 million.

The first transaction was the sale of 9,000 net acres and some related production to Extraction Oil & Gas for $82 million. The second involved 4,000 net acres, with 17 horizontal producers and 150 vertical wells, which were sold to Synergy for $125 million. In each case, according to Struna, the properties sold by Bayswater “fit them better than they fit us.”

Following the transactions, Bayswater retains some 17,000 net acres in rural Weld County, mostly northeast of Greeley. Although a longtime vertical operator, the company is a relative newcomer to horizontal drilling. To date, it has drilled some 45 to 50 horizontal wells, with completion operations on a seventh multiwell pad scheduled for this August.

Bayswater currently is using two Frontier Drilling rigs, with Ensign providing directional services.

While difficult to generalize, Bayswater’s development plans call for 24 wells per section, with pads targeting Niobrara B and C benches, as well as the Codell. Lateral lengths fall into three categories: a standard, 4,300-foot lateral, a mid-length, 6,800-foot lateral and an XRL at 9,400 feet. In two recently drilled pads, one involved eight XRL wells, while another called for 10 wells with 6,800-foot laterals.

The company continues to test varying completion designs. For example, in the above 10-well pad, it employed sliding sleeves and swell packers, with 30 to 50 frack stages, on eight wells, while two used a plug-and-perf and cemented liner completion. On the eight-well pad, it used mainly plug-and-perf technology, with up to 65 frack stages, except for two wells with hybrid completions utilizing plug –and-perf and 30-stage cemented sleeve assemblies.

As a private E&P, Bayswater had perhaps additional latitude to drill through the downturn. Starting in the spring of last year with a single rig, it added a second rig when oil slid to about $70/bbl. Not wanting to lose momentum, “we didn’t deviate from our plan,” recalled Struna.

Annual capex for this year and next is set at $175 million. From a current level of production of about 4,500 boe/d, Bayswater targets some 15,000 boe/d in the year ahead and 20,000 to 25,000 boe/d in 2017. Growth is expected to be predominantly organic, continuing the company’s two-rig program and making some small working interest acquisitions.

Is there a defined exit strategy?

“We don’t want to go public,” said Struna. “Our business model is to buy assets, improve them and exit at the right time. The question is, When is the right time?”

In terms of consolidation possibilities, Struna didn’t rule out the possibility that, in addition to the big players in Wattenberg—Anadarko and Noble Energy—some of the smaller public companies could expand in size such that “the play is sewn up by five or six companies,” he said. “Scale helps.”

For those E&Ps that harken back to earlier goals of gearing up into “manufacturing mode,” allowing them to generate free cash flow, like Anadarko—is that still feasible within a reasonable timeframe?

If Bayswater can hit its 2017 production goal, it would become self-financing, said Struna.

PDC’s Brookman is cautiously optimistic.

“In the next five years, we can probably achieve that as a goal, but it all depends on how quickly we can ramp up and what help we may get from the commodity price,” he said. “We think we can achieve peer-leading growth on only modest outspends of cash flow and minimal draws on the balance sheet.”