A version of this story appears in the March 2018 edition of Oil and Gas Investor. Subscribe to the magazine here.

Operators in Weld County, in the Denver-Julesburg (D-J) Basin of northeastern Colorado, are optimistic, citing high-return Niobrara and Codell wells supported by rising commodity prices. Thus, they are seeking more of a good thing. Several companies have made bolt-on acquisitions, and many are trading acreage in Wattenberg Field. Through these transactions that enable longer laterals or extended-reach wells (XRLs) to be drilled, they are positioned for great production growth in 2018.

Since 2016, E&P companies in the D-J have closed on nearly $2 billion of deals (not counting SandRidge Energy Inc.’s recently aborted plan to merge with Denver-based Bonanza Creek Energy Inc. for $746 million). Successful deals include the following: Crestone Peak Resources LLC paid about $900 million for Encana Corp.’s D-J assets in August 2016. SRC Energy Inc. said last November that it plans to buy drilling rights from Noble Energy Inc. for $568 million, in addition to other acquisitions it has made in the Greeley Crescent area. Verdad Oil & Gas Corp. acquired 30,650 acres from Carrizo Oil & Gas Inc. for $140 million.

Extraction Oil & Gas Inc. has spent $333 million buying greater access to the D-J Basin since the beginning of 2016. It has the best risk-reward wells in the basin, according to analysts at Tudor, Pickering, Holt & Co.

For each of these buyers, XRLs of 7,500 to 10,000 feet have become the norm. Coupled with more intense fracking, they have led to a surge in production, but area gas processing and gathering line pressures cannot handle the incremental output—yet. Waiting for midstream infrastructure to catch up is E&Ps biggest immediate hurdle. The greater Wattenberg Field yields anywhere from 35% to 65% oil depending on location. NGL and natural gas are plentiful.

When we asked some operators what they think is the industry’s biggest challenge in the D-J this year, they uniformly said, “Natural gas processing capacity.” In particular, they cited DCP Midstream’s constraints, although the company has expansions due to come online late this year and again in 2019. DCP even went so far as to promise this in its current investor slide deck, saying, “We will continue to do everything in our power to further expedite this timeline.”

Investors have been skittish about D-J players due to these midstream capacity limitations, and what’s more, the underlying regulatory threats that might dampen activity in the basin. At press time, the Colorado Supreme Court agreed to review an appeals court’s ruling on the role of the Colorado Oil & Gas Conservation Commission, which regulates the basin. Meanwhile, municipalities and green groups along the populous Front Range continue to insist they can ban drilling within their borders and stop fracking activity altogether.

Despite these possible setbacks and delays, operators are pressing ahead, propped up by lower drilling and completion costs and the rich rewards found in the Niobrara and Codell plays in the D-J. In a January report, Jefferies & Co. estimates that that internal rates of return (IRRs) in Wattenberg Field range from 62% for tier 1 wet gas in the Codell Formation and 51% in the wet gas of the Niobrara, to 47% for Codell in the oil core, to 35% in the oil core of the Niobrara.

PDC Energy Inc. is one of the more active D-J players and it, too, has made acquisitions and acreage trades in the past two years, most recently closing a deal in January. But midstream limitations are a concern.

President and CEO Bart Brookman explained. “DCP Midstream’s system is full and line pressures are up, so we expect minimal quarter-to-quarter growth until their Mewbourn Plant 10 comes online. DCP recently announced it’s expected to be online in mid- to late third quarter,” he said. “But we are fortunate to have 25% to 30% of our volumes going to Aka Energy, which has an offload into Western Gas Processing’s system.” Aka Energy Group LLC, a unit of the Southern Ute Indian Tribe, has processing facilities between Denver and Fort Collins, Colo.

DCP’s current capacity of 850 million cubic feet per day (MMcf/d) in Wattenberg will expand by 200 MMcf/d this year, and by another 200 MMcf/d in mid-2019.

“We lowered our 2017 production guidance back in August 2017 due to those line pressures,” added Michael Edwards, PDC’s senior director of investor relations. The company was testing tighter frack spacing of 140 feet between stages, but it’s stopped those tests for now due to the midstream constraints, which could prevent the wells from being turned to sales in a timely manner, skewing data.

Nevertheless, company guidance for 2018 now anticipates 20% to 30% corporate production growth from its focus on Wattenberg Field and its Delaware Basin assets. PDC plans to run three rigs and one frack crew in Wattenberg, where Brookman said these projects deliver some of the highest returns in the country. The $425 million drilling and completion budget allocated to Colorado is based on $50 oil and $3 gas, aiming for 131 well spuds, many in the Kersey area of Weld County, about 60 miles northeast of Denver on rural farm land. These acres are more easily developed than the Niobrara acreage near Greeley, Colo., he said, where urban and suburban challenges add a layer of complexity to many companies’ plans.

PDC claimed approximately 100,000 net acres in Wattenberg (almost 100% HBP) with 1,800 drilling locations at year-end 2016.

“The Kersey area has our best economics. We are drilling to get 1.1 MMboe [million barrels of oil equivalent] on a 2-mile lateral for about $4.5 million, or an F&D cost of $4 per boe. I would suspect that’s one of the leaders in all U.S. basins,” Brookman told Investor.

In 2017, PDC made several deals to expand its reach in Wattenberg, north and south of Kersey. The latest, announced in January, is an agreement to buy assets from privately held Bayswater Exploration & Production LLC for $210 million. It picked up 8,300 acres and the equivalent of two years’ drilling inventory at its current pace. It also traded assets with a second company to consolidate acreage.

To develop the area with horizontal drilling, he said, the company has “pretty much settled on 16 Niobrara and four Codell wells per section, although in areas where there has been less vertical Codell development, there may be an option to drill more than four Codell’s per section.”

These wells are drilled at the same time, then fracked at the same time, and finally, all are turned to sales at the same time.

PDC uses monobore drilling, where it sets surface casing and then drills with one bit through the curve, starting at around 7,300 feet deep, making the turn for the lateral with the same bit to total depth. “We feel 10,000-foot lateral wells are more efficient, so we’ll do as many as we can engineer around our leasehold and prior vertical development,” Brookman said. “We kept our drill and complete costs for 1-mile laterals at $2.5 million … and for 1.5- and 2-mile wells at $3.5 million and $4.5 million, respectively.”

Longer wells minimize surface use, always an important consideration in the heavily populated areas of western Weld County where drilling is encroaching on subdivisions, and in the less-populated eastern part of the county where drilling is mainly occurring in agricultural areas. In addition, longer laterals consolidate operations and improve drilling and completion efficiencies, in addition to amping up the per-well estimated ultimate recovery (EUR).

For now, refracks in older vertical wells in the basin aren’t an industry priority, in Brookman’s view. Earlier horizontal Niobrara wells were drilled with sliding sleeves instead of the more common plug-and-perf method used today, so that alone makes it difficult to re-enter a well, he said. What’s more, full gas processing capacity tends to cause operators to slow down, and so they have enough difficulty bringing on new wells. In addition, Brookman said, he prefers that wells have six or seven years of production history before considering whether to refrack them.

A new dawn

One deal that may have closed by press time is the $649-million merger of Bill Barrett Corp. and privately held Fifth Creek Energy Co. Retired industry legend Bill Barrett, now 89, built the Denver company on a suite of natural gas assets throughout the Rocky Mountain region, but in recent years the company has increased its size and scale and exposure to oil-weighted properties, while at the same time paring back its focus to the D-J.

“We think Fifth Creek provides us a large derisked acreage position, and it sets us up for very economic growth in the future,” said CEO Scot Woodall. “The large, contiguous nature of our acreage sets us apart. We’re mostly in an area that’s about as rural as you can get, with very few occupied structures nearby, so we feel we are well-positioned.

These charts break the Niobrara Formation into specific slices, each with its own economics, according to DrillingInfo.

“This is the dawn of a new Barrett. Really, it’s almost a reset of the company. We can see a multiyear period of growth that allows us to focus for the next decade.”

In 2018, the company plans to operate three rigs and one frack crew, hoping to get 150 XRL wells down. The average EUR is 600,000 boe, 60% oil, on the legacy acreage position. The rate of return on the legacy acreage is north of 40% at a $50-per-barrel price, but as the merger is integrated, the focus may shift more to Fifth Creek’s acreage, because it’s oilier and thus generates a higher rate of return in a range of 60% to 80%. Woodall said.

The recent transaction gives BBG 81,000 more net acres and another 1,200 locations near the Wyoming border in the northeastern tier of the D-J’s oil window, bringing the company’s total inventory to 2,900 locations

“All we will plan is XRLs, with the exception of some shorter laterals that are required due to lease configurations,” Woodall said. “We believe that XRLs are highly economic in the current operating environment, so this acquisition fits our strategy nicely.”

The formula entails up to 12 wells per section targeting mainly the Niobrara on the legacy acreage and the Niobrara and Codell on the old Fifth Creek acreage, for a targeted cost of approximately $4.75 million to drill and complete, although some wells have come in under that cost. “We’ve gone to tighter spacing in the past, like 40-acre spacing, but we think 55- to 60 acre spacing is best in the current commodity environment,” Woodall told Investor.

The Niobrara B is the prevalent zone, with the Niobrara A more prospective to the north and the C more prevalent to the south on the company’s legacy position. The Codell is prospective on the west side of the legacy acreage and is a primary target on the Fifth Creek acreage being acquired.

“The Fifth Creek area is mainly north, near the Wyoming border, but it’s just as prospective as you’d find in the core of the basin, with the Codell thickness of around 20 feet being some of the most prospective in the D-J Basin,” Woodall said.

The company generates a basin-leading operating margin that benefits from having no long-term pipeline takeaway commitments and low leasing operating expense. Basis differentials are expected to be about $2.50 to $3 off the Nymex price for at least the next several years.

Seaport Global Securities LLC analyst Mike Kelly, writing about the deal, said Fifth Creek would be accretive to BBG’s balance sheet, “while enhancing its inventory at a reasonable cost ($6,900 per acre net of $30,000 per flowing boe, per management’s math). The derisked nature of Fifth Creek’s footprint and recent good well results (an average of 1,052 boe/d), shows “some of the best economics in the D-J Basin, with estimated project returns to top 80% at current strip prices.”

That will improve as BBG continues to tweak the completion design. Already, the company’s XRLs feature 1,500 to 2,000 pounds per foot of proppant load and 80 to 85 fracture stages per well.

In many tight sand plays these days, operators are using diverters. BBG has tested these in the past but didn’t see much benefit, and for now has ceased. On a 10-well program in a drilling spacing unit, the company has used diverters on up to two wells on the pad to see how they produce compared to the other wells. But the main factors that matter are frack stage spacing and using more sand, Woodall said, along with choke management that slowly opens up the flow over a period of three to five months, yielding a lower peak IP—but also, a shallower production decline rate.

A key factor is that line pressures across the system operated by Summit Midstream Partners LP here are less than 50 psi (vs. the 300-plus seen in the core of Wattenberg Field). “With 20 MMcf/d in current gas processing capacity (ramping to 80 MMcf/d by year-end 2018), BBG believes its immediate needs are more than covered,” Kelly said.

Discovery Midstream, Rimrock Energy Partners, Cureton Midstream and Sterling Energy are also reportedly expanding midstream facilities or planning to get more active, he said. “Net-net, while infrastructure-related headwinds could remain pervasive in the short term, we see prospects improving materially for D-J players … starting in third-quarter 2018, as various midstream projects start coming online.”

Throughout 2017 the team at Extraction Oil & Gas Inc., many of whom once worked for Noble Energy Inc., enhanced its completion designs, coming to the point of right-sizing the frack. The company plans to spend $770- to $840 million in 2018, to drill at least 175 gross wells. At the midpoint of guidance, this would yield 83% crude oil production growth.

The completion design formula continues to evolve. "It turns out that it depends on the area you're in," said Eric Jacobsen, senior vice president of operations for the company. "It also depends on well flow management, well density and other factors. It's not a one-size fits all situation. I think 2017 was the year of trying bigger fracks and 2018 is the year of doing better fracks, of achieving the best value for any given area."

This continuous evolution could be labeled Gen 37 completion if every improvement were named, he joked, so he hesitated to label what the company is doing as Gen 3 or Gen 4.

Nevertheless, during the fourth quarter, it turned to sales 53 net operated wells and another 26 net wells were completed. Tudor, Pickering, Holt & Co. said in a report that Extraction remains its preferred small to mid-cap stock to own if one is looking for a D-J Basin investment. The pure-play holds 315,000 net acres including its recently acquired Hawkeye area in Arapahoe and Adams counties on the southern end of the D-J.

On the company’s Triple Creek pad, it applied different frack designs depending on which zone it was drilling, whether Niobrara A, B or C or the Codell. In the past year, Extraction drilled and completed 22 horizontal wells, each with 12,500-foot laterals, staggered but going in the same direction). The IPs for this pad had not been released at press time. Two frack fleets were on the pad at once, provided by Liberty Oilfield Services (which just went public).

“We had originally scheduled Triple Creek as a three-year project, but we did it in one year,” Jacobsen said. “The pad is in a semi-urban area; there are some houses in the vicinity about 1,000 to 1,500 feet away. We have a real appreciation of the way our team worked so collaboratively with local governments, the communities and regulators to deliver this in a more expeditious manner than we even expected.”

Extraction has drilled about 500 horizontal wells so far in the D-J and demonstrated its repeated ability to do things well, mostly in agricultural and rural areas. As luck would have it, the company’s recent drilling trends more to areas around the city of Greeley, but Jacobsen said he thinks the company can pivot effectively.

The new area to the south called Hawkeye just saw its second well completed with good results, and other operators that are nearby reported good wells also. To the north, in an area where EOG Resources and others have had success at the Wyoming border, Extraction plans a delineation well this year to assess how the area would fit into its overall D-J portfolio, Jacobsen said.

“It’s oily, it’s rural, it’s contiguous acreage with a lot of potential—all factors we like. We’ll remain focused on the Greeley and Hawkeye areas and the whole corridor on the western edge of the basin,” he said. The company expects to be cash-flow neutral sometime in the second half of 2018. More than 75% of its core acreage is in areas outside the DCP gathering system, therefore, it has capacity to meet its production needs for now, and it is negotiating with other third-party midstream vendors as well.

Consolidation Ahead?

Companies operating in the D-J Basin should go through a series of mergers, leaving the survivors to high-grade the asset base, with the resulting value accruing to shareholders. That’s the opinion of former E&P analyst Ben Dell, founder and managing director of Kimmeridge Energy Management Co. LLC, which in December closed its fourth private-equity fund with $650 million. It makes direct investments in unconventional oil and gas assets in the U.S. for its institutional investors

Dell said, “It’s very clear that certain basins or plays are ripe for consolidation: the Bakken, the Eagle Ford and the D-J in particular.” He has identified eight companies working in Colorado that could or should consolidate.

“We really are making the point that this industry is still very fragmented. In the D-J, you have so many companies with a material position that are the same, that are all doing essentially the same thing. In reality, we think the D-J should be operated as a single field by one big operator. Consolidation would create synergies and optimize well costs, aid in gas processing and so on. We think it would reduce SG&A by up to $1 billion.”

He admitted this idea may look good on paper, but it likely will not happen due to the concerns of executives and corporate cultures. “I don’t see it happening, but it should happen.” The problem is that managements don’t want to lose their jobs, he said.

Bill Barrett Corp., PDC Energy Inc., Bonanza Creek Energy Inc. and others have tremendous assets that overlap with those of Anadarko Petroleum Corp. and Noble Energy Inc. The latter are the largest operators and most obvious acquirers. But the majority of D-J companies, and those in every other basin for that matter, have underperformed the various stock indexes, and shareholders have footed the bill, he said.

Bill Barrett’s acquisition of Fifth Creek Energy, which was to close in the first quarter, is a good first step, he said, an instance of a public company buying a private-equity-backed one. But private companies are focused on a return on assets, and their decisions are based on what will deliver the highest return for their backers, whereas in a public company, the management team decides what to do, and they do not always do what is best for the shareholders’ interests, Dell said.

Kimmeridge owns some Bill Barrett stock, but doesn’t own any other D-J public companies, he added.