Oil and Gas Investor Niobrara Spotlight: Colorado’s D-J Basin Settles In

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[Editor's note: A version of this story appears in the March 2021 issue of Oil and Gas Investor magazine. Subscribe to the magazine here.]

After a flurry of consolidations large and small, the main Colorado portion of the Denver-Julesburg (D-J) Basin is broadly expected to have a quieter recovery year in 2021. It could almost be said that the recent consolidations in the play started at the top of the league table and is working its way down.

The largest operator, Anadarko Petroleum Corp., was acquired by Occidental Petroleum Corp. in August 2019. In October 2020, just 14 months later, the second largest operator, Noble Energy Inc., was acquired by Chevron Corp. Other deals of various types have transpired as well.

The D-J Basin mostly produces from the Niobrara Shale but has been in conventional production for many decades. It also extends into Wyoming but is distinct from other plays in that state, notably the Powder River Basin. In contrast to the action in Colorado, the Wyoming section of the D-J remains primarily the province of smaller independents.

Back in the Centennial State, the larger operators have indicated that the outlook for their D-J/Niobrara operations is steady on for this year. There were extensive curtailments last year, and most seem content to let it ride.

In its fourth-quarter 2020 earnings call Jan. 22, Chevron’s production outlook included “full-year Noble production of about 250 Mboe/d.” In addition to the D-J, Noble had extensive operations in the Permian Basin.

“We are stronger with Noble,” said Mike Wirth, chairman and CEO of Chevron. “It adds to our geographic diversity and plays to our strengths.”

At year-end 2019, Noble reported D-J production of 153 Mboe/d on 336,000 net acres with proven reserves of 666 MMboe.

Analysts noted that the Noble acquisition happened near the bottom of the current commodity cycle and inquired if there was still a buyer’s market.

Wirth responded, “We may have passed the bottom, and I hope we have. There are some [operators] who still have significant debt, so there may be more sellers than buyers. That said, we don’t have to do anything. We made a very good deal, and we have plenty of work for many years.”

In November, Bonanza Creek Energy Inc., based in Denver, struck a deal to acquire HighPoint Resources Corp. for $3.8 billion. The combined company will have 50,000 boe/d (53% oil) from a consolidated, contiguous leasehold of about 206,000 net acres in the rural D-J Basin.

In announcing the transaction, Bonanza stated, “The combination is expected to create the leading unconventional oil producer in rural Weld County and to significantly increase free cash flow and economic resilience.”

Occidental declined to comment on its plans.

Rigs down, regulation settling

Overall, producers have fewer than 10 rigs running in Colorado as of January 2021, according to the Colorado Oil & Gas Association (COGA), which is down from 20 to 30 over the previous year or so. Of those currently running, most are in oil with one or two in dry gas.

“Ahead of the leasing ban [on federal land], it looked to be a recovery year for oil and gas in the state,” said Dan Haley, COGA president and CEO. “There could be small upticks on private lands, but it’s too soon to tell. Some operators have an inventory of permits, and that work will be tied to the economic recovery, which will depend on getting the [COVID-19] virus under control. If business can get back to work, and people can get back to traveling, that is good for Colorado and good for the U.S.”

Any increase in production is likely to include bringing some drilled but uncompleted (DUC) wells to beneficial operation, but Haley does not anticipate DUC hunting to exceed levels seen in 2019.

As liftings rise, there will be plenty of midstream capacity to get those molecules to market.

“Takeaway constraints have been pretty much eliminated,” Haley said. “Midstream operators and producers have worked hard to get into alignment.”

Early in January, Noble Midstream Partners LP, a master limited partnership, struck a deal with a subsidiary of Chevron to handle substantially all crude gathering and intermediate oil transportation from the Wells Ranch development area to Platteville, Colo., for long-haul transportation out of the D-J Basin. To support that, Noble Midstream leased capacity on Energy Transfer LP’s Wattenberg Oil Trunkline.

The other hurdle for producers has been regulatory, but there, too, the toughest part may be over.

“We have finished the most comprehensive part of the ‘mission change’ rulemaking for the Oil & Gas Conservation Commission, required by SB-181, which passed in 2019,” Haley said.

“That included the 2,000-foot siting requirement. There is still more rulemaking ahead of us, including permit fees and worker certification, but we are hopeful that we can start to see some regulatory certainty and stability. There has been a lot of change, and now we need to see the new system in action.”

Association leaders say they are proud of the work that member companies have done to improve air quality.

“As an industry we are ready to tackle this issue. We have seen that even as production has gone up, emissions can go down. Some of the larger operators are bringing in technologies that have been successful in other basins, but the smaller operators are doing well on their own, including things like tankless production. We have been diligent in sharing best practices.”

Flaring in particular, a “black eye” for the industry, as Scott D. Sheffield, president and CEO of Pioneer Natural Resources Co. has repeatedly stated, is “practically nonexistent in Colorado,” Haley said. “That was even before new rules that limited venting and flaring.

“Our companies have learned to operate under changing circumstances. When times are slow there is more opportunity to make improvements; when times are busy, there is more money to make improvements.”

Broadly, COGA members are equally eager for an increase in demand and production, and a decrease in regulatory change—not regulation per se but upheaval.

“In 2019 the governor changed the mission of the regulators by signing SB-181 into law,” Haley said. “A lot of those pieces have been falling into place. Now we need to see the machine work.”

As Scott Presidge, director of public affairs, put it, “The train is on the tracks, and we know where it’s going. It’s time to see it move.”

Production holding steady

For full-year 2020, the D-J Basin averaged about 475,000 bbl/d of oil with the rate at the end of 2020 closer to 415,000 bbl/d, said Steve Diederichs, vice president of intelligence with data analytics company Enverus (formerly Drillinginfo).

“There were a total of 545 horizontal wells turned to production last year, and our current forecast has the basin’s oil rate declining by roughly 6% throughout this year,” he said. “So despite the price stabilization, we would view 2021 as more of a holding pattern than a recovery year.”

With regard to DUC wells, Diederichs added, “We estimate there are slightly more than 1,000 in the play today and expect a good portion of the wells brought online this year to be drawn from this stockpile. We have heard a couple of public operators state that the vast majority of their completions will focus on DUCs rather than new drills.”

Looking at well designs and performance in the play, Enverus data indicate lateral lengths from 2019 to 2020 increased by 7% from 8,400 ft to 9,000 ft, and EUR increased slightly more than 10% from 510,000 boe to 565,000 boe. In contrast, there was minimal change on the completion side of the job, with the average design holding flat year over year at 1,100 lb/ft of proppant and 29 bbl/ft fluid intensity.

“Relative to other U.S. unconventional plays, the D-J Basin is fairly consolidated after mergers between PDC Energy Inc. and SRC Energy Inc., as well as separately, Bonanza Creek and HighPoint (pending closing),” said Andrew Dittmar, senior M&A analyst with Enverus.

“Extraction Oil & Gas just completed their Chapter 11 restructuring and could play a role in further consolidation, but there isn’t an obvious deal on the table for them,” Dittmar added.

Otherwise, deals in the play could take the form of one of the larger companies selling down their position in the basin to focus on core areas elsewhere in their portfolios.

“With commodity prices higher, acquiring assets using a combination of debt and equity financing is likely more achievable than it was last year for either a private or public buyer,” Dittmar explained. “Overall, though, given its current positioning, M&A activity in the D-J is likely to be slower than in some of the more fragmented unconventional plays.”

Diederichs expects things to cool on the political side in Colorado.

“The Oil & Gas Conservation Commission wants to give operators a chance to work under the new rules, and operators need to determine exactly how the new permit process will work,” he said. “Everyone wants to see how things go long term, so we expect some status quo under the new rules.”

He noted that for all the anxiety over some of the new rules, they are not as draconian as some of what was proposed.

“Look at the soft setbacks for example. There are exception off-ramps,” Diederichs said. “That is very different from what was in Proposition 112 several years ago. That would have imposed shutting operations within the setback.”

There are also significant differences between operations in Colorado and in other basins, Diederichs said.

“The challenges are different than in the Permian or even the Bakken,” he said. “Colorado has more density of development and population than West Texas or North Dakota. Also, industry is less embedded in the state economy. The industry in Colorado does a better job of some things, flaring for example, but in terms of overall emissions, the matter is not quite so distinct.”

Current prices sustainable

The current level of oil prices, $55/bbl for Brent and low $50s for WTI, “can sustain the companies in the Niobrara and D-J Basin,” Diederichs said. “At that price deck, there is a fairly favorable rate of return and no ongoing risk of bankruptcy.”

He elaborated, “Last year’s downturn has shifted the focus of many producers from growth to generating free cash flow. So even if oil prices stay where they are or climb, there may not be a great deal of new drilling. I think there has been a systematic change in the way investors and operators view returns.”

What counts as profitable will also partly determine how much consolidation there is in the play.

“There are a handful of small private companies in the basin,” Diederichs said. “But the play is not really as fragmented as they are the Permian or the Bakken.”

The cooling regulatory environment is a mitigating factor for M&A, Diederichs added.

“The wrench in the works was the setback and other new rules,” he said. “Colorado had that looming political change hanging.

“That said, the Chevron [acquisition of Noble] and the Oxy [purchase of Anadarko] deals went through. But those were corporate deals in which Colorado production was just a part. For most operators in the basin, I think they will want to see the water clear a bit, especially to determine how much drilling inventory they have under the new setback rules.”

Andrew Finley, principal with Goolsby, Finley & Associates and Encompass Energy Consulting in Casper, Wyo., anticipates “more of a holding pattern with only modest drilling due to regulatory environment and the current state of the industry.”

“Consolidation is down, but opportunities still exist for entry to the play or further consolidation,” he added. DUCs “will certainly have a larger focus because the drilling dollars have already been put into the ground.

“I think drilling programs will remain modest in 2021. DUCs are controlled by frac crew availability. We may see long lead times for fracking by the end of the year as we have seen in the past.”

Most broadly, Finley said development is controlled by downside price exposure in this environment.

“We seem to have a floor at $45 to $50 per barrel at present,” he said. “At current prices, we will see an uptick in completions throughout the year because we have not been replacing reserves, and decline will continue to limit cash flow and potentially damage perceived value of properties.”

Citing data from the Colorado Oil & Gas Information System, Finley noted 138 wells drilled through October 2020 producing 125 MMbbl of oil and 840 Bcf of gas. Projections for the full year were 145 MMbbl of oil and an even 1 Tcf of gas.

“As with any evaluation of this type, these numbers will be different depending on who calculates the numbers and what assumptions are made to ‘clean’ the data to get something useful,” Finley explained. “Wells drilled in 2021 are expected to increase only slightly based on current conditions.”

Finlay elaborated that data suggest the IPs and EURs are relatively flat versus 2018 and 2019.

“This is somewhat misleading because a larger percentage of these wells are pad wells with offsets versus previous years,” he said. “Also, these data may reflect choked-back production. On the whole, I estimate these data are indicating 10% to 15% increase in completion efficiency. We are starting to see 3-mile laterals, also hybrid fracs using 150,000 to 450,000 barrels total fluid, including 5 million to 10 million pounds of sand in 50 to 60 stages.”

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In March 2020, ConocoPhillips sold its Niobrara assets in the southern D-J Basin to an undisclosed buyer, widely believed to have been Crestone Peak Resources. The $380 million deal concerned 98,000 net acres in northeastern Colorado producing about 11,000 boe/d in 2019. Crestone was formed in 2016 with backing from The Canada Pension Plan Investment Board and The Broe Group. Crestone’s existing acreage is in the Greater Wattenberg Field of the D-J Basin.

Slightly northwest of the D-J Basin, SandRidge Energy Inc. sold its assets in the North Park Basin to Denver-based Gondola Resources LLC in the middle of December 2020 for $47 million in cash.

Wyoming D-J more quiet

The regulatory environment in Wyoming has been stable, which has allowed producers to make steady plans. The Wyoming Oil & Gas Conservation Commission requires 500-ft setbacks, a rule that appears to be working for all stakeholders. That said, at least one operator, Samson Energy Co. LLC, has an internal goal to achieve at least 1,000 ft of setback for all new wells.

Although Samson had planned to drill about 20 wells in 2020, it did not drill any operated wells because of the collapse in oil prices.

“We are contemplating drilling 15 to 30 wells this year,” said Keith St. Gemme, senior vice president of operations with Samson, “but would like to see oil prices firm a little bit first. We have been producing 2,000 to 3,000 barrels of oil per day for the last couple of years and expect that to continue in 2021.”

The D-J Basin in Wyoming is different from the D-J in Colorado, notably because both drilling and completion costs are very low at about $4 million per well. As a result, there are fewer than 20 DUCs in the entire Wyoming D-J. Also, the majority of the operating companies are privately owned.

“There are currently 18 operators in the Wyoming D-J Basin with Codell permits,” St. Gemme said. “In our opinion, this needs to be consolidated down to two or three operators.”

The Wyoming D-J sees 400 to 1,000 Mboe EUR (90% oil) for a 2-mile lateral. Wells have IPs of 750 to 1,200 boe/d. Operators have progressed toward 2.5- and 3-mile laterals and are seeing proportionate EUR increases.

Completions vary by operator. Samson Energy favors slickwater jobs with complex diversion schemes around 1,000 lb of proppant per foot of lateral. Sustained oil prices of more than $50/bbl could increase the rig count in the Wyoming D-J to two or as many as five.

One similarity with the Colorado D-J is that there have been quite a few midstream projects expanding the Wyoming D-J infrastructure over the last few years. There are quite a few options for gas and oil gathering, processing and transportation. Because of that, it is expected that there will only be a little expansion of existing systems but no significant new projects in the immediate future.

“I like our position,” St. Gemme said. “We don’t chase individual well statistics or try to play to maximum initial production. We’ve drilled several good wells and focus on return. As a result, we have seen fairly consistent results across our field.”

He also noted a small irony in statistics: when the performance of wells, fields and even companies are compared, the numbers are usually normalized to thousands of barrels of oil equivalent.

“We are already in the oily window, so when people talk in terms of Mboe things can get somewhat confusing,” he said.

Anticipating consolidation

A bit of the history of Samson Energy is in order. Samson Resource Co. was founded in 1971 by Charles Schusterman of Tulsa, Okla. He was eventually succeeded by his daughter, Stacy Schusterman. In 1986 the business was incorporated as Samson Investment Co. It grew to be the largest privately held oil and gas company in the U.S., and in 2011 about 80% of its assets were sold to an investment consortium lead by KKR. That business is known as Samson Resources LLC.

Samson Energy has had operations in several plays. In 2018 it sold the majority of assets and is focused on the Wyoming D-J.

“The intention is to sell it or drill it out,” St. Gemme said. “And with the way the equity markets are looking, we expect we will just drill it out.”

The rest of the Wyoming D-J is also small companies, and St. Gemme expects that a larger company, public or private, will consolidate the play, possibly down to two or three operators.

“This is the Wattenberg of Wyoming,” he said. “We’ve got a great acreage position that is more oily and more accessible than some of the positions in Colorado. There are some public companies that are active there, but they seem to be more grassroots. Still, it would make sense for one or another of the operators in the gassier window to move up.”

Detailing that accessibility, St. Gemme added, “When all those gas plants were being built in Colorado, those gathering systems were extended into Wyoming, so we have multiple options. Similarly, for oil, there were several pipelines run down from the Powder River Basin that go past us, so there is plenty of gathering, processing and transportation for oil, gas and liquids.”

Water is not as much of an issue in the play as it is in others, notably the Permian Basin.

“We had an operation in the Delaware Basin, and those fracs were just enormous,” St. Gemme said. “Our frac jobs here are about a one-fourth that size. We have no problem getting water. We tend to make deals with owners to buy and accumulate water until we need it. That helps us and them to plan the best use of that resource.”

Samson Energy does not currently recycle produced water, mostly because there is not the scale at present to make it practical.

“We would consider it if needed,” St. Gemme said. The same goes for disposal. “It’s not as much an issue as in Colorado, at least not yet,” he added.

That sense of balance and collaboration extends to the rest of Samson Energy’s operations.

“We engage with the city, county and state,” St. Gemme said. “Ask around Cheyenne; engagement with the community is our formula for success.”