For those with a bent for betting, a decision on “playing the ponies” may at times come down to this: Do you go for broke with a “win” bet, or do you lower your risk by wagering on a horse possibly coming in second or third with a “place” or “show” bet?

In the unconventional energy sector, the near-consensus “win” bet has been placed on the Permian Basin, while the Scoop/Stack is deemed by many to deserve a bet to at least “place.” And if we were all soothsayers, we might even try wagering via a “trifecta,” a bet that requires not only picking the top three finishers correctly, but also getting their order across the finish line right.

Investors looking to spread their bets may want to consider the increasingly attractive outlook offered by the Niobrara/Codell producers in Wattenberg Field of the Denver-Julesburg (D-J) Basin. Historically overlooked due to the small number of public players, the play has recently garnered increased investor interest. Factors include an initial public offering that added a new public E&P; acreage acquisitions or swaps that have given producers more scope to drill wells with longer laterals; and anti-fracking initiatives that failed to qualify for the November ballot in Colorado.

Perhaps most important, however, is the simple combination of sound economics and low-risk drilling, coupled with plenty of inventory. True, fewer benches are being developed currently than in the Permian. But too often has the D-J Basin’s resource potential been written off, only to be revived as the industry finds new methods to economically develop existing or newly found reserves.

Two E&Ps with assets in both the Permian Basin and the Niobrara play speak highly of the economics they achieve in Wattenberg Field in Colorado.

“If people take our Wattenberg capital and calculate the finding and development (F&D) costs from reserves we’ve generated through our drilling, our returns are probably as competitive as any basin in the country,” said Bart Brookman, president and CEO of Denver-based PDC Energy Inc. “And for the returns we’re getting, the Wattenberg offers some of the lowest risk drilling in the country. The combined low-risk, high-return feature is what makes the Wattenberg so unique.”

Moving the breakeven bar

Anadarko Petroleum Corp. now has some 1,200 horizontal wells producing in the D-J Basin, which is expected to be a major contributor to its plans to drive companywide oil production growth at a 12% to 14% compound annual growth rate over the next five years. Its plans call for Anadarko to drill more than 350 wells in the Niobrara/Codell play in 2017, including the company’s first wells with three-mile laterals.

Anadarko’s before-tax breakeven cost to drill wells in the D-J, assuming a minimum rate of return of 10%, now stands at a West Texas Intermediate (WTI) price of less than $30 per barrel (bbl), according to Craig Walters, Anadarko’s vice president of operations for Wattenberg. The breakeven price factors in the “minerals-interest uplift” related to wells drilled on the Land Grant, although the latter acreage has been declining in terms of its share of overall activity, noted Walters. Anadarko’s net revenue interest in the D-J, combining mineral and non-mineral rights, currently averages about 92%, he said.

At record production of about 248,000 barrels of oil equivalent per day (boe/d) in the third quarter, or just over 40% of the company’s U.S. onshore output, Anadarko generated “a significant amount of free cash flow” from the D-J Basin in the period, according to Walters.

What is the “secret sauce” helping these companies, and other E&Ps in the Niobrara/Codell play, to generate such attractive returns?

A dryer removes cutting from drilling fluid
on Synergy's Kawata pad, which features 10 mid-length lateral wells.

Clearly, eye-opening improvements in terms of efficiencies contribute, which along with cost concessions on the part of oilfield service companies have resulted in remarkable progress in bolstering economics. And many see these gains continuing, albeit at a reduced pace.

“Continuous improvement is ingrained in our culture,” said Walters. “We’ll always find ways to do things better. But the learning curve becomes shallower as the program matures.”

Over 18 months through the third quarter of last year, Anadarko saw days-to-drill cycle times for D-J Basin wells drop by over a third from 6.6 days to 4.2 days. Drilling costs decreased by as much as 45%, falling from $97 per foot to $53 per foot. And completion costs improved by 56%, dropping from $201 per foot to $88 per foot.

From late-2014 onward, Anadarko has made numerous changes in its drilling and completion practices, according to Walters. These include changes in drilling mud, casing design, longer laterals, tighter stage and cluster spacing, and the application of different frack treatments depending on the specific formation being completed.

With the Niobrara A bench largely absent on its acreage, Anadarko has generally used a development plan of 18 to 22 wells per section. This typically incorporates six wells in each of the Niobrara B, Niobrara C and Codell zones, with two wells in some cases being added in each of the B and C benches.

While Anadarko has previously drilled extended reach lateral (XRL) wells longer than two miles, or over 10,500 feet, it has plans to drill still longer, three-mile laterals early this year.

A Halliburton crew member readies wiper plugs for installation in the cement head prior to cementing production casing on Synergy’s Kawata pad targeting Nobrara A, B and C, as well as Codell, horizons.

The move to three-mile laterals in this instance was driven by surface constraints on an industrial park located near the I-25 highway running from Denver to Cheyenne, Wyo., east of Greeley.

The first well on the six- to eight-well pad was due to spud in the first quarter and will produce from both Niobrara and Codell formations.

“My understanding is that we’ll be among the first to attempt a three-mile lateral,” said Walters.

Anadarko is also in the fore in its water-handling, or “water on demand,” system, which currently consists of some 150 miles of underground water pipe that can feed four frack crews at a single time. Last year, the system provided a substitute for 250,000 large truckloads of water and eliminated 5 million truck-miles, according to Anadarko.

In addition, Walters emphasized Anadarko’s efforts to operate in as compatible a manner as possible with local communities, citing its decision to use, among other equipment, Liberty Oilfield Services’ new “Quiet Fleet.” The latter is designed to reduce noise levels threefold, compared to a conventional fracking fleet, according to the company. The newly designed equipment began operating for Anadarko at the start of the year and is described by Walters as a “game changer.”

Other vendors for Anadarko include Calfrac Well Services on the completions side. Drillers are Nabors, Precision Drilling Corp. and Extreme Drilling Corp. To address the noise issue on the drilling side, Walters said Anadarko has also installed special equipment on the mud shakers.

Inevitably, the big question presents itself: How does Anadarko compare its two favorite basins?

“The D-J is a more mature basin from a horizontal development standpoint,” said Walters, noting that parameters are typically well-defined in terms of EUR, drilling and completion costs, the availability of oilfield services and vendors, as well as product takeaway. “When you drill a well in the D-J, you know almost exactly what you’re going to get,” he observed.

By comparison, Anadarko’s position in the Delaware Basin “has greater uncertainty surrounding all those parameters today,” noted Walters. “But when you fast forward and get to the point where the Delaware is as mature as the D-J Basin is today, it’s probably going to look better than the D-J. Right now, the D-J has the edge on a breakeven oil price, but the Delaware will lap us very, very soon. We’re super excited about the Delaware.”

Capital and operational efficiencies

Like Anadarko, PDC Energy has interests in both the Niobrara/Codell play and in the Delaware Basin.

Setting aside the Delaware, a key objective of PDC has been to capture the further benefits accruing from its acreage trade in Wattenberg Field with Noble Energy Inc. The swap called for PDC to trade 11,700 net acres in exchange for 13,500 net acres from Noble. The trade helped create more “blocky” acreage that is better suited to development with long-lateral wells.

In its Middle Core area, where most of PDC’s $490 million Wattenberg capex will be focused this year, the acreage trade with Noble resulted in a more consolidated position of roughly 70,300 acres, up from an earlier 60,000 acres. In addition, PDC’s working interest for the second half of last year expanded to approximately 90%, up from about 65% before the acreage exchange.

“The acreage swap was incredibly important for PDC from a satellite view of driving additional capital efficiency and operational efficiency,” said Brookman. “You’ll see continued focus on longer laterals in 2017 and 2018. And you’ll see a huge focus on what we call the ‘swap block’ over the next two to three years. The swap block, encompassing close to 30,000 net acres, accounts for almost one-third of our 96,000 net acres in the Wattenberg.”

PDC has attained technical enhancements in recent wells it drilled on the eastern flank and northwest corner of the swap block, underscoring the quality of the reservoir.

For example, in the northwest corner, PDC has had positive results from its 10-well pad LDS project, where it has tested tighter stage spacing, new choke management methods and increases in proppant loading of up to 55%. However, it believes it has isolated the gains primarily to tighter stage spacing rather than increased proppant, which it had boosted up to 1,800 pounds per foot from 1,100 pounds per foot earlier.

Ongoing tests at the Cockroft well on the eastern flank support this. Relative to a current Middle Core type curve of 685,000 boe, PDC has seen outperformance at the Cockroft well similar to that seen at the LDS project. However, it was achieved by initially lowering stage spacing to 170 feet, down from the prior practice of 200 feet, with proppant intensity held at 1,100 pounds per foot. Tests are ongoing at Cockroft to further reduce stage spacing to 145 feet.

“We’re seeing tremendous incremental productivity from shorter stage lengths, as well as flowback methods, and we’ve set aside for now the additional sand concentrations,” said Scott Reasoner, PDC COO. “We’re not seeing additional sand concentration making a difference in this particular area. We think that 1,100 pounds per foot is going to be adequate, and the way these wells are performing above their type curves is mainly related to stage length.”

PDC has also drilled its first XRL well in the swap block, which is outperforming its Middle Core type curve of 850,000 boe. The well was drilled with stage spacing still at 190 feet and thus offers potential room for further improvement to tighter spacing of 170 feet or 145 feet, noted Reasoner. The well is part of the eight-well Loloff Farms pad southwest of Cockroft.

“The consolidated block, with a single team operating in the area, gives us significant operating and capital efficiencies,” summed up Brookman. “And the early data on the completions front, from wells surrounding the block, have been very encouraging.”

Is there much more room to capture further efficiencies?

“Absolutely,” said Brookman. “This puts our destiny a little more in our control given the increase in PDC’s average working interest. We’ll have much greater control of our capital budget.”

For its entire Wattenberg program in 2017, PDC plans to connect 150 wells to sales. This “turn-in-line” count represents an increase of more than 20% vs. 2016 in terms of one-mile equivalent wells. The higher Wattenberg activity level is in turn expected to be the primary driver in growing companywide production in 2017 by some 40% or more from last year’s level.

With the rig count rising in the Wattenberg—and PDC planning to add a fourth rig in mid-summer—are there signs of rig and oilfield service costs moving higher?

“Operators probably have to be prepared for that,” said Brookman. “I think you’re likely to see some increases, but I think they’re going to be relatively modest. I don’t think anyone is fully healthy yet. For now, costs are pretty stable.”

With PDC generating sizeable free cash flow in the fourth quarter of last year—albeit due in part to a 50% decrease in completions vs. the prior quarter—is funding a “modest overspend” projected for the early ramp in the company’s Delaware operations made a little easier?

Production from Synergy Resources’ 10-well Kawata pad in Weld County, south of the city of Greeley, is anticipated to be online in the second quarter.

“Conceptually, cash flow from the Wattenberg can help launch the Delaware technically in the first couple of years,” said Brookman. “We have $235 million that we’re going to spend in the Delaware in 2017, just to get it up and running. But even with the overspend, we’ll still be strengthening our balance sheet, with our debt-to-EBITDA forecast to come down to about 1.8x EBITDA from 2.2x now.”

How would PDC compare its two favored basins in terms of maturity?

“All the various stacked zones make the upside in the Delaware different,” observed Brookman. “The technical upside in the Delaware probably makes for a first innings or second innings baseball analogy, while the Wattenberg is probably more like sixth or seventh innings. I think investors love that we have layered the Delaware into that.”

Close to homes

In terms of building its acreage and drilling inventory, Synergy Resources Corp. has made several very significant acquisitions, most notably in the Greeley Crescent development area. That transaction, made with Noble Energy last year, by itself added 33,100 net acres to Synergy’s Wattenberg acreage, almost doubling the company’s position.

Of its core Wattenberg position, Synergy considers over 47,000 net acres to lie in the “fairway” of the field, offering over 1,000 drilling locations. The largely contiguous acreage allows for longer laterals that are expected to be a mix of mid-lateral (MRL) (<7,500 feet), long-lateral (LRL) (<10,000 feet) and XRL (<12,000 feet) lengths. The company’s 2017 development plan provides for drilling 68 MRL and 34 LRL wells (gross).

While consolidating acreage in the fairway, Synergy has also been pruning acreage that is considered noncore. Early this year it sold about 10,000 net undeveloped acres with some associated production for $71 million, trimming its acreage by more than 8% in areas outside its near-term drilling plans.

“We will continue to pursue accretive opportunities that complement our high-quality acreage,” said Synergy CEO Lynn Peterson, “as well as divest of properties that are not in our drilling plans over the next several years.”

Synergy has tackled some of the larger development projects in areas that are sometimes close to neighboring communities. For example, from its Evans pad, located just south of the city of Greeley, Synergy has finished drilling 22 wells, comprised of 13 LRL wells with 10,000-foot laterals and nine XRL wells with 12,000-foot laterals (i.e., 2.5-mile wells). The first six wells have been completed, with completion of a second tranche of six wells just beginning. All completion operations at Evans are expected to be finished by late April or early May.

Directionally, the wells are drilled north of the Evans pad under a housing development for 2.5 miles. Vertical wells that pre-dated the housing were plugged and abandoned in preparation for the Synergy development plan. Earlier, on the four-well Bestway pad located north of Greeley, Synergy had similarly drilled under the city with laterals headed directionally to the south.

“The Evans pad is on the south side of the city, and the Bestway pad is on the north side, and the two meet in the middle,” said Mike Eberhard, Synergy COO. “That’s what gets us under Greeley without encroaching on the city.”

As E&Ps generally look to achieve economies of scale in their development programs, specific challenges arise in undertaking a
project of this magnitude.

“For the Evans pad, if we did 11 wells this year, and 11 wells next year, we wouldn’t need nearly the facilities there we’ve had to have to drill all 22 wells,” observed Eberhard. “Conversely, you don’t want the Evans pad to be a three-year drilling program in the middle of communities. There’s got to be a balance between the level of activity at a location and the impact you have on the communities.”

From an operational standpoint, “it’s handy because everything is there. The rig is there, it just walks from one well to another. The frack crew sits right where it is, you just move the iron from well to well,” he continued. “But there comes a point of diminishing returns as you get bigger and bigger. You have to design for flush production. But you don’t want to have so much in place in terms of facilities, such as takeaway, which is at risk of becoming oversized after six months of production.”

Operationally, the wells are not without occasional issues. The XRL wells are mostly drilled “as a necessity, and not a preference. A lot can happen in the wellbore when you get that far out,” said Eberhard. If LRL wells can be used, they are preferred because “we can drill them quickly, complete them in a reasonable amount of time and have less exposure to wellbore issues.”

Saturated with drilling mud, a pair of safety gloves reflects the efforts of a day’s work by a Precision Drilling crew seeking Niobrara Shale for Synergy Resources.

In terms of potential cost inflation for oilfield services, Synergy has budgeted for a 10% increase this year, but expects the incremental costs to be largely offset by continued efficiency gains. For example, Synergy is now able to drill a 10,000-foot lateral well in about six days at a cost roughly in line with what it cost to drill a 4,200-foot lateral in 11 days in the autumn of 2014. Further efficiency gains will be smaller, but ongoing given the “very good” rig and completion crews it works with in the basin.

“The beauty of the D-J is that it’s always been a low-cost basin,” said Eberhard. “We have a controlled growth right now. The rig count is not going through the roof. It’s not at the fever pitch of the Permian.”

In addition, performance has been enhanced by the use of technology that has become significantly more affordable during the downturn. One example is Synergy’s use of rotary steerable technology in drilling wells at its Evans pad. One well is said to have set a record in drilling 19,000 feet in a single run, using Baker Hughes’ Auto Trak bottom hole assembly.

In addition to the Evans pad, Synergy has several pads that are starting to produce or are due to come on production. These include Fagerberg, where 14 wells are producing at pressure-managed rates in line with expectations; Williams and Wiedeman, with nine wells and eight wells, respectively, due to begin completion operations in the first quarter; and Kawata, a 10-well pad, with completion operations due to commence in the second quarter. Synergy will continue drilling with a two-rig program in 2017.

Synergy’s projected ramp in production has attracted the attention of Wall Street. A number of analysts have pointed to Synergy’s peer-leading growth in production in 2017 to 2018—some estimate an annual rate of around 60%—as a key factor in arriving at a progressively cheaper enterprise-to-EBITDA valuation as future EBITDA grows along with production gains in 2017 to 2018.

Avenues to growth

With an already highly consolidated acreage position in the Niobrara play, Bill Barrett Corp. is evaluating avenues to accelerate growth if recent WTI prices hold in the low to mid-$50s/bbl. Organic growth, by adding a second rig, is perhaps the most visible path, although the Denver-based company is also open to acreage acquisitions or swaps and other expansion options.

As with other E&Ps, Bill Barrett lost operating momentum in 2016, but closed out the year having generated cash flow in excess of its $100 million capex budget and having grown production slightly. Partly, Bill Barrett achieved this by dropping one of two rigs in early 2016 and then laying down the second rig in March. The company resumed drilling operations in September of last year.

Bill Barrett estimates it has 60,000 total net acres that are suitable for development with an average 9,500-foot XRL well. Of this, about 50,000 net acres are concentrated in the company’s largely contiguous northeast Wattenberg position. Drilling and completions costs, including facilities, for XRL wells have fallen some 48% since early 2015, dropping from $8.25 million to $4.25 million.

Since resuming operations, Bill Barrett has drilled an initial four wells on a pad in its southern area, located just south of the Platte River. It also drilled nine wells on a central area pad, and then moved the rig back to the northern acreage where operations continued. Earlier last year, a 15-well pad and a nine-well pad were completed and put on flowback in April and June, respectively.

Bill Barrett has now drilled close to 100 XRL wells, which are now drilled “routinely” in six days, down from 18 days with its initial well, according to CEO Scot Woodall. The primary targets are the Niobrara B and C benches, with some also tapping the Niobrara A zone and, in limited cases, the Codell horizon. Some of the wells drilled in early 2016 came in at costs of less than $4 million, he added.

Woodall has taken several measures to position Bill Barrett to pursue a number of options. An equity offering in December raised $109.7 million, boosting the company’s cash position to about $275 million, and at the end of 2016 the company had an undrawn credit facility of $300 million. Hedges to protect 2017 cash flow currently cover 6,342 bbl/d (equivalent to 57% of third-quarter 2016 oil production) at $58.74/bbl.

What WTI price would make the prospect of adding another rig appealing?

“It’s something we’re considering pretty strongly,” said Woodall. “A price in the low to mid-$50s gives us a fairly good rate of return. We’re currently running sensitivities on a number of factors, including higher activity. People invest in smaller E&Ps like ours for growth, so we have to resume a growth trajectory at some point. Fundamentally, we’re a growth-oriented company.

“We have the ability to slow down activity and be cash-flow positive, or we can ramp up activity and show a pretty nice growth profile,” said Woodall. “The consensus analyst estimate has us growing close to 10% with a one-rig program in 2017. If we add a second rig sometime this year, we’d be around 30% growth, comparing 2018 over 2017, depending on when we add a rig over the course of this year.”

While Bill Barrett has a solid acreage position in northeast Wattenberg, the company remains on the lookout for adjoining or nearby acreage, he said.

“There is acreage coming available. We’ve done a few small transactions, and it looks like there’s going to be more turnover in acreage as people buy into XRL development. You’ll see acreage change hands via swaps or acquisitions. I think that’s positive, and we’ll participate at some level.”

A dawn frost clings to winter grasses along the banks of the Platte River meandering through the D-J Basin north of Denver.

Woodall also indicated a willingness to entertain possible corporate combinations, an issue that has “made sense” for smaller E&Ps in the lower commodity environment of the last couple of years.

“I think there are a lot of synergies for these $1 billion-enterprise value companies to consolidate, whether in-basin or with a company in another basin,” he observed. “You can save a lot of G&A and other costs related to being public. As a bigger company, you have greater access to capital and it’s cheaper. And you should be able to contract goods and services cheaper with greater size and scale.”

In mid-January, Bill Barrett disclosed in a Form 8-K filing it had indicated interest in a combination transaction with a reorganized Bonanza Creek Energy Inc. following its Chapter 11 proceedings.

“With a similar acreage profile in the D-J Basin,” wrote a research note by Macquarie Capital (USA), “the combination could create operational synergies and provide scale to two relatively undersized players in the basin. Additionally, the combination would eliminate duplicate overhead and create a larger organization with what would likely be a number of synergies on the cost front.”

Woodall was tight-lipped beyond acknowledging the 8-K. “We’ll see where it goes,” he said.

Synergy Resources’ Kawata operation in Weld County, Colo., sits just off of County Road 46 near Platteville.

With a surge in deal flow following the OPEC meeting, Woodall welcomed prospects of further possible consolidation or other transactions to shine a light on the relative attractiveness of the D-J Basin. While Permian acreage has often transacted at roughly $30,000/acre, assuming $30,000 per flowing barrel or more for associated production, the D-J has generally traded at acreage prices of $5,000/acre to $10,000/acre, based on a similar valuation for production, he said.

“Given breakeven economics that are not that dissimilar, plus the low cost of entry, I think people are going to start looking for another investment choice, another basin to invest in,” commented Woodall. “I’m optimistic that the D-J is going to come to the front of some of these deals. You don’t have any of the worry about a basis blowout, given plenty of oil pipeline capacity. And the overhang of legislative issues, such as the ballot initiatives and regulations, is now more under control. I think you could start seeing more acreage changing hands, new players coming in, and perhaps some consolidation.”

Of course, the knock on the D-J Basin is that it has fewer potential zones to develop. However, over time, that may change, as it has several times in the past.

“In addition to developing the Niobrara and Codell benches, we’re testing other horizons in the basin,” said Walters. “As a prudent operator, when you have a stacked column, such as we do, we’re not completely focused on just the Niobrara and Codell. There are other horizons that have historically been productive, are productive today, and which we think might be productive utilizing horizontal drilling and hydraulic fracturing completions on those horizons.”

Anadarko is quick to say it doesn’t have any go-forward large development plans for any of the new horizons currently. “We’re still in the testing phase,” said Walters.

Previously, Anadarko and other E&Ps in the basin conducted tests on the Greenhorn. Now, in search for further upside in the basin, the focus has shifted to other intervals.

“We’ve drilled some Sussex wells, and we’ve permitted a couple of J-sand wells. And we plan to do some more of this on a limited basis,” said Walters, noting Anadarko’s first J-sand well was scheduled to spud in February.

Chris Sheehan can be reached at csheehan@hartenergy.com.