Burnishing The Rockies’ Rep

[Editor's note: A version of this story appears in the July 2019 edition of Oil and Gas Investor. Subscribe to the magazine here.]

It’s no secret that some E&Ps in the Rockies have faced headwinds specific to the region. Opponents of energy, for example, have tried hard to restrict industry activity in Colorado through ballot initiatives. While the most recent such attempt was defeated, Democrat-led legislative action has altered the industry landscape, opening the door to meaningfully greater local control.

Some optimists argue that reduced uncertainty, in itself, can offer a more attractive environment for E&Ps—even if many of the more restrictive measures are unpalatable. In addition, it has often been the case that E&Ps are already used to working with local community leaders in the course of business. But this is not to ignore the cloud left hanging over the industry in Colorado of late.

Is the cloud over Colorado about to lift?

Speaking at Hart Energy’s DUG Rockies conference in Denver in mid-May, Mike Kelly, managing director with Seaport Global Securities, sounded a positive note for Colorado E&Ps in light of the “more certainty” the energy sector may have in the wake of Senate Bill 181.

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“Don’t be afraid of the D-J names,” said Kelly, referring to operators in the key Denver-Julesburg Basin. “As soon as the Street gets comfort, you will ultimately see valuations improve.”

Certainly, if investor sentiment does improve, there is ample room for Colorado-focused E&Ps to narrow the valuation gap between their and their peers’ stocks. For example, on a ratio of enterprise value-to-EBITDA (EV-to-EBITDA), the Colorado stocks trade at a multiple discount of 1.8 times (“almost two turns”) vs. a peer group of E&Ps operating in the Permian Basin, said Kelly.

This is despite several metrics highlighting the attractive economics of the D-J. Comparing four basins, including the Permian, the D-J Basin had the lowest finding & development (F&D) costs in two of the last three years. Also, operating margins in the basin were “competitive,” he noted, making for the best recycle ratio (operating margin divided by F&D costs) on average over the three years for the four basins.

As E&Ps in Colorado adapt to the state’s evolving regulatory environment, Denver-based Anschutz Exploration Corp. has taken further strides toward significant development programs being planned by E&Ps in Wyoming. According to Anschutz CEO Joe DeDominic, the Powder River Basin (PRB) has “literally tens of thousands of locations” that the industry is looking to drill.

Anschutz currently has two rigs operating in the PRB and plans to add a third rig in the fourth quarter of this year. Leasehold held by Anschutz totals some 460,000 net acres with an average net revenue interest of 82%. Net production is running at about 7,500 barrels of oil equivalent per day (boe/d), currently 78% to 79% liquids, and is forecast to rise to roughly 8,000 boe/d early in 2020.

Converse and Campbell Counties

Overall, the industry has about 23 active rigs in the basin, led by Chesapeake Energy Corp. with six rigs, followed by EOG Resources Inc. and Devon Energy Corp., each with four rigs. Much of the recent activity is concentrated in Converse and Campbell counties in the south of the basin. By well count, the most active E&Ps in the PRB in 2018 were EOG with 50 wells, Chesapeake, with 41, Devon with 28 and Anschutz with 18.

“All the activity is in the core southern part of the basin right now,” said DeDominic, at DUG Rockies. “People are largely being conservative in their decisions of where they drill. That southern area is proven, more mature; that’s where you see the wells being drilled, the rigs being active today.”

Privately held Anschutz has an operated program this year that provides for 28 wells to be drilled and completed. The first part of the year will focus primarily on delineation and spacing tests in the Niobrara and Mowry, while the second half will be devoted mainly to Turner development and growing production. The well counts are expected to be 14 in the Turner, nine in the Niobrara, two in the Mowry and three vertical pilot wells.

“It’s a really strong, emerging oil basin with multiple stacked targets,” said DeDominic. “We think this is a future giant basin for the oil and gas industry. We believe the Niobrara and Mowry will come along over the next couple of years. You’ll see them moving into development mode with certain operators and in certain areas. We think there’s a lot of potential in the basin.”

Examining the PRB’s stratigraphic column, DeDominic traced the development of the basin from vertical production to horizontal development of mainly tight sandstone packages and, more recently, the basin’s growing production from the Niobrara and Mowry resource plays.

“Historically, there’s been huge stacked pay in this basin from vertical wells without water technology,” with cumulative output from vertical wells to date exceeding 3 billion boe, said DeDominic. “If you look at the production stream from those wells, it’s around 82% to 83% oil. So this is an oil basin; it’s not a gas basin, where people are trying to make liquids and make a play. It’s an oil basin.”

In recent years, as horizontal drilling gained dominance, almost 80% of all horizontal wells drilled in the PRB since 2010 targeted two tight sandstone packages, according to Anschutz data. Some 42% targeted the shallower Teapot, Parkman, Sussex and Shannon horizons, with typical IP30s of 1,500 boe/d, while 37% targeted the deeper Frontier/Turner interval, with IP30s of 2,000 boe/d or more.

Far fewer wells, however, have targeted the Niobrara and Mowry resource plays, which have accounted for only 18% and 2%, respectively, of all horizontal well objectives.

“We think there is a lot of potential in those zones,” said DeDominic. “We know those are hydrocarbon-bearing. Those source rocks, the Niobrara and Mowry, generated the oil that’s been produced out of the tight sandstones. So there is oil amongst this whole system. It’s a matter of testing it, finding the best areas and moving it into development mode.”

Turner Spacing Tests

In terms of well spacing tests, Anschutz has conducted three drilling spacing unit (DSU) tests in the Turner Formation, with four wells on each DSU. The average IP30 for the 12 wells was 980 boe/d. DeDominic said Anschutz’s plans “leaned toward the aggressive side” with the four-well test and, with oil in the low-$60s, the company would “back off” from the four-well per DSU.

“We’ve seen Devon and EOG do some four-well tests. They’re both [now] in the three-well per DSU in our area,” said DeDominic. “Devon, Anadarko [Petroleum Corp.] and Chesapeake have all tested three-well DSUs. The rates for the Turner seem to be between two and three based on thickness and operator preference.”

A spacing analysis by Anschutz showed that, when moving from a two-well scenario to a three-well scenario per DSU, recoveries rise from 1.9 MMboe to 2.1 MMboe. However, if continued to a four-well scenario, the recovery falls to 2 MMboe per DSU. Costs per boe are cited at $7.11/boe and $9.29/boe in the two- and three-well scenarios, respectively, but rise to $13/boe in the four-well scenario.

These costs per boe are “extremely competitive,” said DeDominic. “There are thousands of Turner locations to be drilled. The Turner is pervasive across this whole area. We see a long-term development program at very robust economics going forward.”

Turning to the Niobrara, the source rock for the shallower sandstone plays, DeDominic said Anschutz tended to drill vertical pilot wells, log them, and come back later to drill horizontally. To date, it has drilled three wells, with two targeting the upper Niobrara and one targeting the lower Niobrara. One well, in the “chalk” part of the upper Niobrara, had a peak month production of 1,133 boe/d.

Niobrara Already Economic

“At current well costs, which are not development mode well costs,” added DeDominic, “that main chalk zone in the middle is already economic, by our calculations. The question is: How to do this efficiently to maximize your economics? With 200 feet of pay in the [entire upper Niobrara] section, how do you drain that effectively? What spacing? What ‘wine-racking’ of your wells?

“There are more tests going on,” he continued. “We’re drilling two spacing tests in our block: one at 660 feet, which would be eight wells per DSU, another at 750 feet, which would be seven wells. EOG is doing a similar test in its area. We’ll likely have some results by year-end or early next year that could kick the Niobrara into development mode in some parts of the basin and further appraisal in other areas.”

Covering an extensive area, as indicated by the 2009 USGS Assessment, the Niobrara has the potential for “tens of thousands locations as the play matures,” according to the Anschutz presentation.

The Mowry is “another major source rock,” charging the Turner/Frontier and other deeper formations, noted DeDominic. A vertical well by Anschutz showed a Mowry pay section of 120 feet, and topical issues centered on the best landing zone and upcoming completion design. “We’ve just drilled our first horizontal Mowry well with a 9,200-foot lateral,” he said, “and we’ll be completing that in June.”

Prior Mowry wells for which public data are available include four wells by EOG with average IP30 rates of more than 2,000 boe/d, noted DeDominic. Two sets of two wells were drilled to lateral lengths of 9,100 feet and 9,200 feet in the EOG program.

Crestone

In Colorado’s D-J Basin, private operator Crestone Peak Resources is also planning for growth. Crestone’s five-year plan calls for a compound annual growth rate of production of 14% during the period from 2018 to 2023. The plan is based on being free-cash-flow neutral at a West Texas Intermediate (WTI) price of $50 per barrel (bbl), so that debt stays essentially unchanged at under 1 times EBITDA at each year-end.

Crestone was formed in 2015 to acquire the D-J assets by Encana Corp. It has financial backing from the Canada Pension Plan Investment Board (CPPIB), known for being one of the largest institutional investors and operating with a long-term investment horizon. Crestone has 51,000 net acres in the D-J Basin’s Wattenberg Field and produced about 32,200 boe/d in the first quarter.

Crestone “is blessed with good acreage, which translates into some really good operating costs,” according to its CEO, Tony Buchanon. Well breakeven costs are “around $30/bbl,” he said, and lease operating expenses (LOE) and general and administrative (G&A) expenses on a combined basis are less than $5/boe. For the first quarter, these came in at $2.29/boe for LOE and $2.14/boe for cash G&A.

Crestone has a two-rig program for 2019 and plans to grow production by about 18% this year, accelerating to 27% in 2020. Its acreage is in the deeper southwestern portion of the D-J, “where we get really good well performance, really good rock,” said Buchanon. The development program for 2019 calls for 120 gross-operated wells and participation in nonop wells.

The acreage is, however, “more urban-y,” commented Buchanon. “We do have dealings in the urban corridor. We communicate with the local communities to make sure that we are answering their questions and that we’re continuing to perform at a high level. It’s very important to us that we have a social license to operate in the basin.”

As for issues involving local control, “Crestone has been kind of on the forefront of working with these local governments, mostly because that’s where our acreage has been,” he said. “We have agreements with the towns of Firestone, Erie and Dacono. This has enabled us to come in and drill our wells in and around these towns, to work with them and to be a really, really good partner with these communities.”

A “Lot More Certainty”

As regards Senate Bill 181, said Buchanon, “I think this will give us a lot more certainty at the end of the day, now that the field has been leveled. The rules are actually out there, and we’re pretty confident that, if they’re going to change, they’re not going to change significantly. We’re really encouraged that we can work with our communities and still be able to develop oil and gas in Colorado.”

The two rigs employed by Crestone are from Ensign’s fleet of electric rigs that can be plugged into the local grid, said Buchanon. “With the electric rigs, you can actually walk on the drill floor and still have a normal conversation,” he remarked. In addition, Crestone uses Liberty Oilfield Services’ “Quiet Fleets,” which build in-sound reduction technology as part of its fracturing equipment.

“Here in the D-J, the Quiet Fleets are really important,” said Buchanon. “When you go onto a location with Liberty’s Quiet Fleets, you can have a normal conversation while they are actually fracking. I’ve been in the industry for a long time; I’ve done a lot of frack jobs. But I didn’t even know that we were fracking the first time I walked up onto their location with their Quiet Fleet.”

Looking ahead, Buchanon noted that, with WTI prices recently exceeding the $50/bbl benchmark to reach cash-flow neutral, Crestone would “probably generate $300 to $35 million of free cash flow this year. And we see that flowing through 2020 and beyond,” he added, with possible uses being returns to shareholders, paying down debt or making further investments.

Does the CPPIB, as Crestone’s long-term backer, help guide a path for Crestone?

“They’re a long-term investor,” said Buchanon, noting that CPPIB has an investment portfolio that totals around $380 billion. “They’re targeting long-term investments that generate solid returns. What’s interesting is that they view the D-J Basin as a very, very good basin. And they think it’s an opportunity in which to continue investing money.”

Deep Pockets

Would the CPPIB be receptive to funding possible acquisitions by Crestone? How about in urban areas?

“What is unique as regards the CPPIB is that we can do a lot of cash deals; they have deep pockets for that, and we can pay cash,” said the Crestone CEO. “But they’ve given us quite a range of opportunities. We can go from Drillcos all the way to paying cash or doing something in-between.”

As for evaluating urban versus rural opportunities, Buchanon indicated both options were on the table.

“We’ve been working in and out of urban environments since 2016,” including locations such as Firestone, Erie and Dacono, where Crestone has operating agreements, he recalled. “If there are opportunities where other operators don’t have the agreements to drill those wells, we would be there to pick that work up and utilize our agreements and our relationships to do that.”

“We would not shy away from that,” said Buchanon. “We think it’s an opportunity.”

Innovations and Engagement

Founded in 2002, Extraction Oil & Gas Inc. now ranks among Colorado’s top oil and gas producers and has built a significant acreage position. However, the company is perhaps more frequently recognized in two other areas—its technological innovation and its community engagement—according to Eric Jacobson, senior vice president of operations at Extraction.

 “Our company is particularly known for the technologic innovations we have brought to Colorado, as well as for our stakeholder engagement,” said Jacobsen. “We take much pride in our engagement with local communities to create best-in-class developments. Our willingness to work with communities to minimize or eliminate some of the temporary impacts traditionally associated with energy development is widely recognized, and we believe it is our competitive advantage.”

Extraction had an output of about 80,000 boe/d in the first quarter and is targeting an average of 90,000 boe/d for the full-year 2019. The company holds nearly 290,000 net acres in the D-J Basin, of which 159,000 are considered “core” acreage. Less than one quarter of the latter has been drilled, leaving 18 years of inventory to be developed at the current pace, according to Jacobsen.

Extraction’s development program is focused not only on the traditional Niobrara zones—the Niobrara A, B and C intervals—but also the Codell horizon. “Another advantage is the areal extent and the exceptionally high quality of the Codell Formation across most of our portfolio, including North Hawkeye, Windsor, Greeley and Broomfield,” commented Jacobsen.

A slide shown by Extraction indicated a WTI breakeven price, assuming single well economics and a 10% discount factor, of $38/bbl for the D-J. The basin ranked second only to the Permian, at $34/bbl, based on data sourced from RS Energy Group. Jacobsen pointed to the company’s “premium” Broomfield assets, in particular, as being “as even more competitive than the $38 breakeven price.”

First 3-mile Lateral

In looking at lateral lengths and drill times, Extraction has been able to drill 2-mile wells in five days, spud-to-spud, and recently cut the drilling days to below four days for five such wells, according to Jacobsen. The company has gone on to drill more than 60 wells with 2.5-mile laterals and is looking forward to drilling its first well with a 3-mile lateral later this year, he added.

Extraction has continued to seek “better, faster, safer” methods to increase efficiencies, said Jacobsen. Advances in its completions have meant crews are averaging 5 million pounds of proppant per day and 16 stages per day per crew. As with some of its peers, completion services are provided by Liberty Oilfield Services’ Quiet Fleet, which has reduced sound for Extraction “by two-thirds.”

With “all-in cycle times” (including cleanout, flowback) coming down 40% since 2016, the resultant drop in costs has meant the D-J leads other basins in terms of 2-mile lateral well costs. For example, for the development of its Greeley and Broomfield acreage, F&D cost are expected to be “somewhere below $7/ boe, a very competitive position for not just this basin, but the U.S. as a whole.”

Recently, in Broomfield, Extraction has “worked very collaboratively with local governments to thoughtfully plan our development,” said Jacobsen. “We realized this was a community that hadn’t seen a drilling rig in decades. We purposefully paused the pace of our development and began working with elected officials and residents to help inform community members and answer their questions.”

Items included in the plan are:

• Closed-loop systems to capture 99.9% of emissions;
• Electric grid power for not only the drilling rigs, but also for production facilities that will allow “for silent running for years and years to come;”
• Air monitoring; and
• Fully programed safety systems that “facilitate automatic shutdowns and prevent incidents before they occur.”

“We’re drilling today in Broomfield on our sixth well,” said Jacobsen in mid-May, as the project ramped up.

Moreover, Jacobsen noted that the Rocky Mountain region is poised to benefit from around 1 billion cubic feet per day of incremental gas processing capacity by year-end, not just from the Elevation Midstream facilities serving Extraction, but also from new capacity due to come online from DCP Midstream, Western Midstream Partners, Rimrock Midstream and others.

“By the end of 2019, we expect the D-J Basin to be unlocked,” said Jacobsen.

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