Expert Q&A: RigUp sits down with WoodMac’s R.T. Dukes

Where do we go from here?

As we progress through a volatile 2Q, we’re sitting down with one of the most well regarded E&P analysts on Wall Street to discuss the state of the North American upstream industry.

RT Dukes Image

RigUp: M&A in the Permian Basin remains a hot topic. This quarter we’re starting to see majors or larger E&Ps like Exxon and Marathon making sizable acquisitions in West Texas. Is this a signal that the consolidation is coming to an end? What do you expect in terms of M&A in 2Q 2017, particularly as it relates to the Permian Basin?

R.T. Dukes: There will be more, but there aren’t a host of companies looking to exit like there were 18 months ago. We’ll continue to see deals, but the next wave of consolidation will happen over a longer period and will be when economies of scale begin to matter. Add up guidance from many of the top operators, and it might be sooner than we think.

RigUp: Wall Street has dramatically increased Capex estimates for the back half of 2017 and into 2018. Based on your basin by basin analysis, is North America going to exceed production expectations for the year and if so, is that bearish for the commodity markets?

R.T. Dukes: That’s dependent on your expectations! With that, we’re on track to surpass the 2015 peak in oil production near the end of 2018. I suspect that probably outpaces what most people thought would happen. Of course, that could all change to be lower or higher if prices decide to settle closer to $40 or $60.

RigUp: Are we in a world now that should be focused on the “Call on Permian” instead of the “Call on OPEC”? Or is that still wishful thinking and posturing?

R.T. Dukes: The Permian is a significant player on the global stage, but it’s not big enough to single handedly suppress prices for a long time. It will create problems in years that demand growth slips or when global supply outperforms. That will cause year to year problems, but in the long-term, it’s not the sole price setter.

RigUp: Given the strength in production growth in West Texas, there’s some scuttlebutt that we’ll run into takeaway capacity issues starting later this year. What are your thoughts?

R.T. Dukes: We definitely could, but the pipes are on the way. We don’t expect any prolonged blowout in prices due to takeaway capacity. The problems are intra-regional and on the other side of those long haul pipes. Many of the major producers plan to produce so much they need to think about who their buyers are and securing demand for their production.

RigUp: Shifting conversation about takeaway capacity to the Northeast, what are your thoughts on basis differentials in the Northeast? How big of an impact is Rover Phase 1 going to have on the market? Do E&Ps adopt an even more aggressive productive behavior thereafter?

R.T. Dukes: It’s not just Rover, but the other pipes that will add Northeast connectivity too. Add all the projects together and the region looks set to have excess capacity for a few years post 2018. As a result, producers are going to realize prices that are much better than what they’ve seen in recent history.

RigUp: For the last 6 months, the industry has been talking about “core natural gas wells” having been drilled and completed already. What’s your opinion there?

R.T. Dukes: We’ve seen high grading to the highest degree over the past couple of years with oil and gas prices seeing cyclical lows. That is changing on the oil side as operators are already stepping out, but there’s still a big inventory of core natural gas wells that have yet to be drilled. Above $3 natural gas, we’ll see more drilling outside of just the Marcellus and Haynesville.

RigUp: RigUp’s marketplace has seen the market visibly tighten for frac for 1Q this year. In some cases, based on geographical and technical requirements, there’s no spot availability until June 2017. What’s your perspective on the medium-term and long-term supply / demand for frac horsepower in North America?

R.T. Dukes: Costs are going up! The jobs are bigger, and we’re going to need more HHP than we had in 2014. Barring a price shock to the downside, we’ve probably seen the lows in completion costs and the name of the game is back to managing those costs. The industry seems to underestimate how big those swings can be, and we’ll need new horsepower sooner than most believe.

RigUp: Could you go into further detail concerning completion design strategies that E&P companies are deploying currently?

R.T. Dukes: Bigger has been better, but we’re starting to see that normalize. We’ve seen diminishing returns in certain areas as operators use more than 1,500-2,000 pounds of proppant per foot. While proppant and completion prices were low, operators had the luxury of pushing the limits. Now that costs are going up, we expect we’ll hear talk of more efficient completions utilizing the right amount of proppant, water, horsepower, etc.

RigUp: Specific to oil and gas technology, what’s the current state of the industry and their willingness to modernize? At RigUp, we’ve been blessed with a strong contingent of supportive and transformational companies that have championed our adoption. But at the same token, we’ve been told by certain operators that the internet just won’t work in oil and gas. What’s your take? Will the technology adopters win?

R.T. Dukes: I’ve seen it my entire career covering oil and gas: “If it ain’t broke, don’t fix it.” We’ll always have companies like that as long as they can capture reasonable margins, but we’re not in a world where anyone expects $5 natural gas or $100 oil. The potential margin just isn’t as big as it was. A lot of people believe we’ve already cracked the code, and everything here will be small gains. The problem with not worrying about small gains today is they add up to big savings over time. Technology is as important as ever, and I suspect those companies that are avoiding tech are much more likely to be the next casualties of the shale revolution.

To learn more about Wood Mackenzie, visit woodmac.com.

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10 Predictions in Oilfield Services for 2017 – An interview with Infill Thinking’s Joseph Triepke

As 2017 gets off to a start, RigUp is sitting down with some of our industry’s most respected experts to share their insight, thoughts, and wisdom as we exit a tumultuous downturn in the commodity markets. Our conversation today with oilfield service veteran Joseph Triepke should provide some insight into how we prepare for the recovery and what to expect in oilfield services this year.


Joseph Triepke, Infill ThinkingJoseph Triepke
is the founder & principal research analyst of InfillThinking.com, an independent oil and gas business research firm. For approximately a decade, Joseph analyzed the oil service and drilling industry for large Wall Street institutions. In 2016, he launched a new industry facing market research firm: Infill Thinking. The firm provides clear updates to oilfield decision makers, exposing new angles on stories and trends that really matter.


Q: After the dust has settled it seems like everyone is ready and anxious for the race back up. The balance seems to be rising service pricing balanced against equipment reactivations and supply reintroductions to the market, what are your thoughts?

A: As far as I’m concerned, your read on the market is spot on. The service space is chomping at the bit, eager to feast after several years of famine. During Q1 2017, we are looking for market share leaders in virtually every segment to push pricing higher. Reactivations are coming, but we may be in a sweet spot for service pricing improvement to start the year as prices are still generally too low to justify large scale reactivations. That could change after a few rounds of re-pricing.

Q: If pricing power returns as you expect, where do you think we start to see the inflection first?

A: Prices will likely first start to inflate across the completions supply chain, starting with pressure pumping. In fact, frac pricing started to inch up during Q4 2016. Double digit increases in frac pricing will be commonplace early this year as calendars are filling up for available spreads. Drilling rig day rates are another area to watch for inflation. The land rig market as a whole remains grossly oversupplied, but the higher end of the market is much tighter than the weekly rig count suggests. For example, super spec rig utilization is tracking above 80% industry wide. Historically this is the utilization level where pricing power returns to contractors.

Q: Since the fall, there’s been a lot of discussion and anxiety over potential future sand constraints (and in some cases, fears that sand constraints could actually limit US supply). From the conversations you’re having with pressure pumping providers and service companies, what’s the outlook on frac sand?

A: At this point, no one we talk with is concerned with frac sand supply in the Lower 48. By that we mean sand is plentiful at the basin level in the biggest plays. Consumption is tracking at about half of 2014 peak levels. We talked to the largest pumper of sand in late December and were told that water supply (while nothing to panic over) is more of a challenge than sand supply. What’s more concerning to us is potential bottlenecks in last mile logistics, meaning proppant delivery from transload facilities to well sites. This is where we see a potential choke point worth monitoring early this year.

Q: Any other gating factors or potential bottlenecks we should be on the lookout for?

A: I’m keeping an eye on labor. The highest quality workers have been or are being called back. The further down the call lists contractors move, the more issues you might have. And you could start to see wage pressure too, starting this quarter in particularly active basins like the Permian. With tens of thousands of workers returning to O&G, we’ll soon start to see just how many of the downturn’s casualties have permanently left the industry.

Q: The theme of “decoupling” services and flattening the multi-level supply chain emerged in the last commodity upcycle and the E&Ps that were early to that theme benefitted in the last downcycle – it also happens to be one of the key value propositions of RigUp – what are your thoughts on this theme as the industry goes back to work in 2017?

A: Taking costs out of the system structurally rather than cyclically is more important than ever. So too is finding structural efficiencies. The Lower 48 D&C activity recovery at oil prices half of prior highs has been impressive. To us, it underscores the critical importance of permanent cost savings. As service pricing reflates, we can’t lose efficiencies or this recovery won’t last long. I think that’s where new solutions like RigUp come into play. The recent downturn catalyzed the adoption of new methods. The coming upturn will institutionalize these new methods.

Q: Everyone is predicting a flood of E&P M&A (led by the strength of Permian Basin takeouts), what are your thoughts on OFS M&A as we head into 2017? Are there more interesting deals that could ensue following the GE/Baker Hughes & CSL/BJ Services announcements late 2016?

A: There’s not as much consensus about a wave of OFS M&A as in E&P because of valuation arguments. But I think deal flow could surprise to the upside this year, due in part by an intense focus on adaptive technology by the leading players, similar to the GE/Baker deal you mentioned. As far as specific deals go, we recently identified four likely OFS buyers in a note to Infill Thinking subscribers.

Q: Given the valuation challenges, how do you see these deals getting done?

A: Look for companies to use their equity as valuation equalizing currency similar to what Patterson-UTI did in the Seventy-Seven Energy deal late last year. We could also see buyers chase more attractive values in the privately held space. As earnings visibility emerges and estimates are revised higher, valuation concerns could start to fade. My sense is bid/asks are closing in this early stage of the upturn, and we could see some significant deals signed soon.

Q: You mentioned technology as a driver of M&A. What themes are you seeing for innovation on the service side?

A: Brute force factors of unconventional development like lateral length, stage counts, and proppant volumes are beginning to test diminishing return boundaries. As this plays out, we see a big push toward gaining sub-surface clarity so that brute force factors can be harnessed more effectively. This is a focus point right now for OFS technologists. The industry still does not understand the complexity of nano-darcy rock, but innovators are working on advanced science to gain visibility and design around the complexities of unconventional formations.

Q: Do you have a prediction on the US rig count this year? There’s been lots of talk about a lower ceiling given efficiencies, do you subscribe to that view?

A: I do. I believe the rig count will be hard pressed to achieve prior cyclical highs. Same concept as the 1980s – we simply need fewer rigs going forward to unlock production. So far everyone’s been surprised by the strength in drilling activity. Before the OPEC meeting, I had forecast 2017 would close with about 815 rigs working. When I made that prediction, there were about 563 US land rigs working, and today we are already up to 640. I still think we finish the year under 1,000, but we could run up a little over 900 ceteris paribus.

Q: What about specific basins, especially the Permian Basin?

A: In the Permian, we’ve been forecasting aggressive 2017 growth for months. Shortly after the OPEC meeting in November, we projected 150 rigs would return to work in the basin (assuming OPEC’s actions backed their words). In just six weeks since then, 40 rigs have already gone back to work in the play. We are standing by our +110 additional rig expectation there, which is the highest we’ve seen from anyone for the Permian this year.

10 Predictions for Oilfield Services in 2017


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DUCs and Drilling in the Bakken: Oasis Petroleum Case Study

Our guest author, Tanya Andrien, is the Market Director for Finance and Oilfield Services, and Product Manager for Analytics at Drillinginfo. We were interested in her observations because many of our clients use our marketplace to secure pricing for work on DUC wells.

Oasis Petroleum: Drilling and DUCs in the Bakken

Nowadays, everyone seems to be tracking the Drilled but Uncompleted well inventory (DUCs) to forecast supply and evaluate how operators will strategically utilize DUCs to lower capital requirements in 2016. I am curious whether operators will complete their DUC wells faster than they add new wells, allowing them to maintain production levels now but potentially jeopardizing 2017 results. As an example, I analyzed Oasis’ operations in the Bakken. While Oasis doesn’t appear to be completing its DUCs in lieu of drilling new wells, their activity demonstrates a change in strategy during 2015 and into 2016. Here are some observations:

Oasis has almost 90 DUC wells in the Bakken Grouping the DUC wells by drilling vintage, and color-coding by county, shows a definite shift in activity.

Drilling Info Graphic
FIGURE 1: Oasis DUC Wells in the Bakken by Vintage, Colored by County. Data as of May 15, 2015

As shown in Figure 1, DUC wells drilled prior to June 2015 vary across four counties, and appear to be “deferred completions”, or wells that probably require an oil price recovery to be completed. By contrast, DUC wells drilled after June 2015 suggest Oasis high-graded activity to only McKenzie County, which is consistent with their rig movements, as illustrated in Figures 2 and 3 below.

Drilling Info GraphicFrom March 2014 through June 2015, Oasis was drilling in six different counties (Figure 2). As of July 2015 to present, Oasis has focused solely on McKenzie County (Figure 3).

But did they complete some of their early vintage DUC wells in 2016? I compared Oasis’ May 15 DUC well count to its count in early February, and Oasis had only reduced the DUC count by a few wells during that time in Mountrail, Roosevelt and Williams counties. Oasis does not appear to be completing many of its early vintage DUC wells.

Drilling Info Graphic
FIGURE 4: Oasis New Wells by Month of First Production, Colored by County. Data as of May 1, 2015.

What about McKenzie County? The DUC count in McKenzie County decreased by 5 wells from early February to mid-May, however, we haven’t seen the production results yet as no new McKenzie County wells were brought online since Q3 2015.

Based on Figure 4 above, Oasis has only reported new production in Q4 2015 from Williams and Mountrail counties, and there are no new wells in 2016. Since Figure 1 indicates that Oasis has continued to drill new wells in McKenzie County, the lack of new wells coming online is probably explained by the Confidential Well exception in North Dakota; Oasis reported 26 wells in McKenzie County under Confidential status as of May 15, 2015.

Despite drilling activity being focused on McKenzie County, Oasis’ permit activity since January 2015 demonstrates that, while they filed the greatest number of permits in McKenzie County (130 permits), Williams, Mountrail, and Roosevelt counties were also important, with 51, 41, and 36 permits filed, respectively.

Drilling Info Graphic
FIGURE 5: Oasis Permit Filings, 1/2015 – 3/2016. Data as of 5/16/16.

The recent permit activity in Roosevelt County suggests Oasis may begin drilling here soon, at which time Oasis might also complete its DUC wells in Roosevelt. Monitoring rig activity will be the next indicator of a change in focus.

¹ This count reflects a literal definition of a DUC well, meaning drilling is finished but there is no evidence of production or completion. Because we track rig activity on a daily basis, some of the DUC wells may have been drilled as recently as two days ago and are part of normal work-in-process inventory which Oasis may plan to complete immediately.