[Editor's note: This story is the first installment of a three-part outlook series which appears in the December 2018 edition of Oil and Gas Investor. Subscribe to the magazine here.]

In January 2018, NASA demonstrated something new, even radical: autonomous X-ray navigation using millisecond pulsars to determine the location of an object moving at thousands of miles per hour in space. The agency said this technological first could revolutionize its ability to pilot robotic spacecraft to the far reaches of the solar system someday.

NASA called its experimental tool SEXTANT (Station Explorer for X-ray Timing and Navigation Technology) after the ancient instrument sailors used to navigate the Seven Seas.

By most accounts, a sextant might be just as likely to help the oil and gas industry navigate through 2019 as any other system. In this issue, Oil and Gas Investor’s editors talked to a wide range of experts on what lies ahead for the upstream, midstream and oilfield service sectors. But as one of the pundits admitted, “The forecasts of all forecasters are always wrong.” Nevertheless, we asked them for their opinions.

The consensus says that as 2019 begins, operators will continue to drill and complete wells at a fairly slow pace in most U.S. basins. At press time, some E&P companies already had signaled that they intend a slowdown from fourth-quarter 2018 through at least first-quarter 2019 for a number of reasons, which had some oilfield service sales reps crying in their beer. On third-quarter conference calls in October, the CEOs of Halliburton Co. (NYSE: HAL), Schlumberger Ltd. (NYSE: SLB) and several frack-related and sand companies said they expect a slowdown in the first six months of 2019.

Most observers say shale field delineation and development will pick up steam through the second half of the year as E&P companies begin to whittle down their DUC (drilled but uncompleted) inventory and as several new midstream facilities finally will be completed.

Helen Currie, senior economist with ConocoPhillips Co. (NYSE: COP), cited macro headwinds such as a deceleration of global economic growth, particularly in China, that may stall demand, and the possibility of an oil supply glut, coupled with a tight service sector in key basins.

“When we see red flags being raised by the International Monetary Fund and other forecasters, that gets our attention. I do think companies are working diligently to preserve and protect the margins they’ve achieved through all the restructurings and technical improvements, but a lot will come down to how disciplined these companies can be.”

U.S. oil production has increased by 2 million barrels per day (MMbbl/d) in the past 24 months and was hitting 11 MMbbl/d at press time, six to 12 months earlier than many had predicted. This is a phenomenal increase that E&Ps can be proud of—but they need to preserve their hard-won efficiencies, she told Investor.

She said ConocoPhillips runs its business by taking the long view, and she is not calling for $100 oil any time soon, although, she added, “never say never.

“I see reasons why oil prices should remain where they are today,” she said, meaning $65 to $70/bbl.

Since the downturn, “operators have learned quite a lot,” noted Svetlana Ikonnikova, energy economist for the Bureau of Economic Geology at the University of Texas at Austin. “Where the challenge might be is as big companies go forward with bigger developments, do we have the infrastructure to handle all the production, do we have the people? As we see the boom [in growing U.S. oil supply], do we have the capacity to handle the boom?”

“Clearing the Permian logjam will unleash a slug of crude,” said IHS Markit’s Bob Fryklund. Here, a rig drills in West Texas.

A late October survey of executives by Deloitte indicated 72% of respondents expect West Texas Intermediate (WTI) crude to average $70/bbl or more in 2020. “Even more bullish and in sharp contrast to last year’s findings, 41% of respondents expect WTI prices to average $80 or more in 2020, up from only 5% from the prior year.

“Notably, 2020 could be the year the lid is lifted on prices for Henry Hub natural gas. More than half (54%) expect Henry Hub natural gas will average $3.50 or more per million British thermal units (MMBtu) with a majority of those (35%) expecting $4 or more per MMBtu,” Deloitte said.

“Despite the price recovery, surveyed upstream executives seem to have been so battered by the downturn that they are a bit skittish about embracing a positive outlook,” explained Andrew Slaughter, executive director for the Deloitte Center for Energy Solutions with Deloitte Services LP. “Companies have come a long way in streamlining operations and repositioning portfolios, but they still have much more to do to recover. Added risks are uncertainty around the economy, trade and rising interest rates, which have a greater impact on upstream more than other sectors.”

A World Of Prognosticators

For now, the stars twinkle and blink about oil and gas price uncertainty, infrastructure delays, rising interest rates, rising oilfield service costs and unfriendly investors who seem to be steering a wide path away from E&P equities. These woes are weighing on oil and gas producers and investors even though astounding technical advances continue to partially offset these concerns.

The outlook that emerged during fourth-quarter 2018, when company managements were planning budgets and fine-tuning strategies, was further clouded by a global economic slowdown, especially in energy-hungry China, and the threat implied by U.S. sanctions against Iranian oil exports.

“We’re living in a world of prognosticators who are saying it’s going to be $100 oil and others saying that it’s going to be $30. The ‘punditocracy’ is making bold statements that range everywhere,” complained Allen Gilmer, CEO of Drillinginfo Inc.

Experts disagree on the outlook for global oil demand, and thus, oil prices, but they do see supply being robust in North America. “Looking forward to 2019, BTU Analytics expects the U.S. and Canada alone to add 1.7 million barrels a day of liquids production in 2019 relative to July 2018 [prior to the impact of impending sanctions on Iranian production].”

However, BTU Analytics said it thinks prices will likely remain volatile in 2019 “and due to growing infrastructure constraints across the U.S. oil network, the U.S. is unlikely to be able to save the day, even if oil prices rise further.”

Analyst Marc Bianchi of Cowen & Co. said in a research report that Permian Basin takeaway constraints and a focus on capital discipline will likely result in conservative E&P budget increases for 2019, at least at first.

“We assume 12% spending growth in 2019 and 2020,” he wrote. “We also assume spending in 2019 is somewhat weighted toward second half, resulting in a still sluggish [oilfield service] market to start the year. With oversupply in pressure pumping and frack sand, we expect continued price weakness driving downward revisions.

“However, if current commodity prices are sustained, we would expect E&Ps to increase spending by mid-2019 or even earlier, as availability of pipeline capacity nears. We suspect the North American stocks will remain rangebound until E&Ps increase budgets.”

Cowen & Co. analysts are assuming an oil price of about $60/bbl and an 11% rise in the number of well completions, but this will be accompanied by a “big DUC build” until Permian Basin pipeline capacity comes on by year-end.

One of Spears and Associates’ latest market reports said that it projects global expenditures for oilfield equipment and services to increase 9% in 2019. “This is given the expectation that flat-to-higher oil prices will drive further growth in U.S. activity and trigger the start of a recovery in international and offshore activity,” the oilfield services research firm said.

As operators try to drill within cash flow, within budgets, yet bearing risks, can they maintain a growth trajectory? “Even though they are trying to push technology, they’re also trying not to rely on external capital as much as before, which could constrain their rate of growth,” said UT’s Ikonnikova.

She noted that there are still questions about the environmental and surface footprints created by full field development or pad drilling and how those will be resolved to the public’s satisfaction. At the same time, E&Ps have to understand their rock better now that they are drilling 10,000-foot laterals in cube development mode. The rock changes along that length.

“You need to analyze the data to an unprecedented degree. You may think you’ve drilled one rock when it’s more than that. The game has changed. You cannot cut out just the middle layer; you have to cut the whole cake.”

To that end, next April the Bureau of Economic Geology will release a basinwide report on tight oil resources based on a consortium of 16 E&Ps. The university’s supercomputer has been crunching almost a billion cells in its 3-D model that includes data about seismic, oil, gas, fauna, flora, water, subsurface and surface models on all the producing layers and injection layers in a given tight oil area. The finest resolution is just 3 feet of vertical rock in the many layers of any given tight oil play, she said.

Looking For Opportunities

IHS Markit Ltd.’s Bob Fryklund noted that due to some 3,000 Permian DUCs in inventory, many wells will be completed next year, so a production surge is coming. “Operators will be able to shoot that out pretty quickly, so we see an increase of 1.3 MMbbl/d in the U.S. by fourth-quarter 2019 and more than 60% of that is from the Permian.

“The other big liquids plays are growing too, but at a slower rate, more incrementally. All of them are at an inflection point where the growth rate is 10% or less [of course, individual companies may be growing their production much faster].”

Gilmer told Investor that if he were an independent producer looking for opportunities in 2019, he would acquire older fields where he could employ the latest technology, test refracks, inject natural gas and access low-gravity crudes to blend into the burgeoning light, tight oil mix that is swamping pipelines and Gulf Coast refineries.

Drillinginfo has extremely detailed information on production and breakeven costs for every basin and play, sliced very fine. Based on that, Gilmer said he doesn’t buy the idea some have put forth that the shale tail or decline may be worsening faster than we first believed.

“The core of these plays has lots of places to go; there are a lot of wells yet to be drilled. We still really have no clue what realistic well spacing should be. We have a lot of new technology that has yet to be applied to these fields. And we sure don’t want to lose all those old wells—I believe plugging a well that is producing successfully is a sin.”

He also thinks the recent trend on the part of many large public E&Ps to sell assets and become a pure-play company, in whichever basin, might end up being a mistaken ploy. Based on some mega-mergers that were announced at press time, some people in the C-suite agree that being in two or three key basins or plays is the better way to go.

The Midstream Squeeze

“If you are very narrowly based, you run a risk,” Gilmer said. “Can you get it [production] to market? The bigger companies that are not pure-plays stand to be better off. But even then, I am starting to hear stories of big companies that have been kicked out of the pipelines they’ve been in for years because they’re at capacity.

“The areas that have gotten the most attention [like the Permian] are momentarily locked up—but that is supposed to be cleared up by the end of 2019.”

Simmons Energy, a Piper Jaffray company, said in an October report that takeaway issues “are more complicated than simply the timing of the commissioning of the pipelines.

“Pipelines directed to Corpus Christi are expected to have some logistical challenges in aligning the incremental throughput with the requisite crude storage and export capacity. Virtually every incremental barrel coming out of the Permian needs an export/storage solution as Gulf Coast refining capacity is effectively fully utilized.

“Thus, it is reasonable to expect some logistical gremlins into early 2020.”

RBN Energy Inc. founder Rusty Braziel agrees. “As long as crude oil prices remain at or above current levels, many of the biggest challenges facing producers will be infrastructure constraints—concerns like pipeline takeaway capacity, gathering/processing and downstream markets,” he told Investor.

“Invariably, rapid production growth slams up against a bottleneck of some sort, constraining growth and crushing prices upstream of the bottleneck. Midstream companies eventually build out the needed infrastructure, but in the interim, companies without access to downstream markets suffer. And then, after that infrastructure is built out, there is a pretty good chance that another bottleneck will appear further downstream.

“That is the way the Marcellus/Utica region is playing out for natural gas. The same thing is happening in the Permian for crude and gas. NGLs are battling fractionation capacity constraints in Mont Belvieu.

“This is the new normal,” Braziel said. “As long as we remain in production growth mode—which seems almost certain—then there will be a continuing series of constraints in all growth markets.

“Some will be easy to anticipate, but some will surprise much of the market. Anyone involved in these markets needs to plan accordingly and build a lot of flexibility into their marketing programs. Otherwise, their development strategies may be subject to risks over which they have little control.”

Gilmer said he thinks play diversity may be a saving grace in light of the infrastructure problems that currently plague the upstream sector. “If you think about the broader gene pool, you have a lot of resistance to disease. This is exactly what’s happening now in the oil industry—this is something evolutionary biologists have known forever, but ‘investor biologists’ haven’t paid enough attention to.”

Tip Of The M&A Iceberg

The upstream team at Tudor, Pickering Holt & Co. has been vocal regarding the maturation of U.S. shales and therefore, changes will need to be made in the E&P business model going forward.

“We wholeheartedly believe that 2019 could be a busy year for mergers as the industry turns its eye to public market consolidation after years of private-to-public transactions in basins like the Permian,” the analysts said.

“The Encana-Newfield merger … in our view only represents the tip of the M&A iceberg that will emerge in 2019. Our thesis is fundamentally grounded in the view that shale has matured and as such, companies will look to consolidation to gain scalable cost synergies and inventory. All of this is a healthy [and necessary] evolution in the upstream space.

“Asset level synergies make logical sense as size and scale will allow operators to improve operating efficiencies; however, one of the most highly discussed topics is cost synergies—particularly around G&A. Over time, if equities continue to lag, we could see investors push for greater consolidation, to try and squeeze less efficient operators out of the system, in particular, large-cap companies acquiring smaller-cap peers.”

Simmons Energy also joins the growing chorus that predicts more corporate consolidation lies ahead. When oil prices finally stabilize at a higher level than in the past two years, buyers usually make their move. On the heels of the recent takeovers of Penn Virginia Corp. (NASDAQ: PVAC), Energen Corp., WildHorse Resource Development Corp. (NYSE: WRD) and Newfield Exploration Co. (NYSE: NFX), Simmons senior analyst Ryan Todd wrote that he expects corporate deals will become a greater percentage of total 2019 activity. Even after the shale surge, several E&Ps still report having less than 10 years of drilling inventory, he noted.

“There are ample opportunities for consolidation outside the Permian as well. Further, as the E&P sector continues the transition toward the industrialized business model and core inventory is depleted, scale and scope will likely drive increased consolidation,” he said.

One of the first tenets of portfolio management is diversification, IHS Markit’s Fryklund said, noting most companies have flipped from being mostly natural gas to more oily, and many have downsized to be in fewer plays.

“So is this the right bet? The supermajors are betting on gas and for them, unconventionals are maybe 25% of their mix, but the independents are 60% to 80% betting on tight rock. If you roll the clock forward six or eight years, is that going to be diversified enough?

“There is not necessarily room enough for everyone in each basin,” Fryklund warned. When commenting on possible M&A transactions to come, the TPH team said it “can easily think of more than 10 additional deals” where there should be a strategic asset rationale or cost synergies that would make sense heading into 2019.

“Buckle up, as the upstream merger train has left the station, and next year will likely be a wild ride.”

Parting Words

“The independents still have resilience out there, but don’t get too far ahead of your skis,” advised Mike Watford, the immediate past chair of the IPAA. “You’ve got to have some financial return now. The majors have shown that for a long time, but the independents now have to do it too.”

Watford cited the infrastructure bottlenecks in the Permian Basin and Northeast, and surging oil and gas supplies, as issues that will continue to plague the industry through 2019.

“We think in general that 2020 looks pretty good, but in 2019, the average independent may struggle—of course, it depends on where you are and what commodity you’re trying to capture. The gas side remains very difficult. I think you really have another year where you have to slow down development and that’s going to upset the service side of the business. You’re going to see more folks level-load their activity until they get better pipeline access.”

Conoco’s Helen Currie concluded, “Most executives should remind themselves that they are in a cyclical business. But I think it should be a good year; I say that cautiously. It might be a great year, but it’s safe to say it’ll be a good year.”

Fryklund said he is fairly optimistic that 2019 will be a good year for shareholders, but he definitely sees consolidation ahead, as the universe gets smaller yet has a lot of bigger fish. “Some of the bigger fish get hungrier as they get bigger, and shareholder return targets get bigger,” he said.

Leslie Haines can be reached at lhaines@hartenergy.com.

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