Forget whether the oil industry’s recovery is going to be shaped like a bathtub or a V. That debate is old news. The bottom’s been called, and a tentative recovery is under¬way if you look at the upward move in oil prices, onshore rig counts and A&D activity since last spring. But alas, the caution flag is still out, because the price of oil is bounc¬ing around between short-lived rallies and discouraging setbacks, as traders and bud¬get planners hang on every word uttered by members of OPEC. Each day, we check our smartphones: Where did oil close today?

The people Oil and Gas Investor infor¬mally polled were hopeful, but most described the recovery in less than glowing terms. A few even said it’s premature to use the word. Analysts have said $50/bbl could be the new $90; service companies worry 900 rigs working in the U.S. will be the new 2,000, absorbing all the frack crew capacity while holding oil production flat. At press time the count had just topped 500.

Bellwether service giant Schlumberger Ltd. has shifted from managing in a downturn to recovering the temporary price concessions it made and is renegotiating contracts, according to president of operations Patrick Schorn. In a presentation in late August at Simmons & Co.’s 2016 European Energy Conference in Gleneagles, Scotland, he said service prices need to recover by 20% to 30% to allow sus¬tainable operations.

“It is too early for any improvement in [oil] price to affect E&P investment, as operator confidence and balance sheets must first be repaired. This leaves the service industry in critical condition … if activity does not pick up rapidly.”

The recovery will not be uniform by geogra¬phy, he said. U.S. land drilling will return first, followed by international activity, with offshore and deepwater lagging far behind.

At press time, signs and signals remained mixed. The hoped-for decline in U.S. oil production was underway; through summer, it had fallen by almost 932,000 bbl/d since its March 2015 peak. But the 12-month strip price for WTI had barely budged: On Aug. 29, it was $49.77/bbl and on Aug. 28, 2015, it was $48.93.

Only in hindsight will we know whether the second half of 2016 was truly the start of a meaningful recovery. Bottom line, it is not proceeding as fast as producers, bankers and investors would like—or need.

“We think it’s not really underway yet, because the price of oil is still not presenting an attractive investment for a lot of plays,” said Guy Caruso, a senior energy advisor to the Center for Strategic & International Stud¬ies (CSIS) in Washington, D.C., and former head of the EIA. A recent CSIS report he co-authored noted that in July, OPEC’s output hit a record.

A recovery means different things to differ¬ent companies, depending on their financial picture and the plays in their portfolio of activ¬ity. Data on where rigs are returning to work backs up this thesis, with the Midland, Dela¬ware and Scoop/Stack plays attracting most of the field action and financial backing.

“I do think this recovery is going to be— what’s a good word?—discriminating,” observed David Baggett, founder and manag¬ing partner of Opportune, a Houston profes¬sional services consultancy.

“I don’t think it is going to be the same across the board; it will be selective based on if you are in the better parts of the better plays that have the best IRRs or ROIs.” When we spoke, Baggett was coming off 20 hours of depositions in one week related to energy company bankruptcies or restructurings. The firm is handling 21 such jobs, and he thinks more restructurings are coming.

Sentiment ranges from skepticism to caution to realistic optimism, but capital markets are setting up opportunities, as evidenced by the spate of equity offerings this year.

“I don’t think anybody’s racing out to get a bunch of rigs working,” said Mike Ames, managing director and co-head of energy investment banking for Raymond James & Associates.

“I think they will stick very close to cash flow, and when they have sufficient confidence in prices, they’ll start to make a move. I think because of this downturn we’ve been through, the caution light is going to be on for a little while longer.”

The Raymond James research team says oil will average $80/bbl in 2017 and drop slightly to $75 in 2018, with a long-term out¬look of $70.

Raymond James cites four trends that will drive the budding recovery through the second half. First, the asset A&D market is heating up, especially in the Permian Basin, but even in other basins, with the value gap between buyers and sellers narrowing. Second, equity offerings have increased and, for most, the issuing companies outperformed their E&P peers. Third, scarcity of mature, reliable assets to buy is driving competition between private equity-backed E&Ps and their publicly traded brethren, with private equity bringing some very large deals to the finish line. Fourth, high-yield bonds are showing signs of life, with Parsley Energy Inc.’s recent $200 million offer¬ing just one sign, he said.

“While these factors don’t spell a certain rebound, taken together they indicate the mar¬ket is opening back up and make a compelling case for action,” the report concluded.

Said Ames: “A lot of our clients are cau¬tiously optimistic and hoping that we are right [on our analysts’ call for an upturn]. As prices move up, you’re going to see more activity in more basins as more basins become economic again.”

This is a “creeping recovery” that is setting E&Ps up for problems down the road and pro¬pelling the A&D market, Guggenheim E&P analyst Subash Chandra told us, citing low E&P spending during the downturn.

“If I’m a CEO, I’m in a tough spot. I hav¬en’t explored for a year and a half and I’ve booked my PUDs on $55 oil. I have nothing in inventory beyond that unless oil goes from $55 to $75—or, I buy something, like everyone’s doing in the Delaware.”

The real questions now are, What should E&P companies and investors do going for¬ward, where are the next opportunities, and how have they changed as companies emerge from a two-year slump?

Optimistic as they are, oilmen riding the ups and downs of a volatile industry like to hang their hat on a couple of truisms: First, this com¬modity business is and always will be cyclical and always recovers at some point; and second, in the end, everyone still needs more energy—there is no real substitute for oil and natural gas to fuel the world in ever-increasing amounts as populations and economies inevitably grow.

Indeed, this month, energy concerns take center stage at the United Nations as heads of state, government ministers and ambassadors from more than 150 countries convene for their annual meetings. For the first time, this will be combined with the annual meeting of the World Energy Forum. They and business lead¬ers, academics and financiers will discuss how to provide universal energy access—part of the United Nation’s 2030 Agenda for Sustainable Development.

But most E&P companies and inves¬tors are looking to the near term. What lies ahead for the remainder of 2016 and, more importantly, what will 2017 look like? By most accounts, the recovery appears to be underway, but it may be too early to pop the champagne corks.

Caution is the watchword, our sources say, given that the list of factors leaning toward a recovery, or postponing it, is long, ranging from whatever U.S. Fed chairman Janet Yel¬len decides, to whatever the Saudi oil minister decides. Then too, before most E&P managers crank up the action in any meaningful way, they remain leery of another “head fake” or temporary spike in oil prices that turns out to be just that—temporary.

Talk of OPEC, Russia and Saudi Arabia agreeing to freeze or even cut production can cause the price of oil to rise a bit; but then, talk is cheap, as they say.

Rig indicators

The land rig count bottomed in May and has risen almost every week since then. In early June as we started the second half, there were about 380 land rigs working. A Tudor, Pickering, Holt & Co. (TPH) report estimated that the rig count will rise to just north of 1,000 rigs by 2018’s end, some 18 months away. That’s a steep hill to climb in the meantime.

Sentiment is gradually changing for the better, according to analysts’ meetings with Nabors Industries Ltd.’s Denny Smith. The rig count is coming off the bottom. But he cau¬tioned that rig reactivation is expensive and will become even more so as more rigs go back to work. Rig efficiencies may go backward for a time, he said; for two years the industry has limited itself to using only the best rigs and crews and only in the core acreage. Hiring more crews and restocking rigs with consum¬able supplies could be a challenge.

The U.S. land rig count continues to inch up, but it is basin-specific and tied to either the Permian Basin or Oklahoma’s Scoop/Stack play. Additionally, there are reports that demand has begun for other types of equipment and services, especially specific rig types capa¬ble of allowing operators to continue to push the envelope in lateral lengths and massive proppant loads for bulked-up fracks on mul¬tiwell pads.

As of August, projections for the rig count were still modest. Baird Research esti¬mated 600 to 650 are needed to halt the production decline and restart growth. RBC Capital Markets projected 750 land rigs in 2017 and 930 by 2018. (The count was last above 600 in January 2016.)

TPH said it’s modeling the U.S. land rig count going up more than 48% year-over-year and up 39% again to average about 650 rigs in 2017 and about 850 in 2018, exiting that year at 1,000, but it had a few cautionary remarks as well.

“The next upcycle won’t be frictionless,” a TPH report said. “The Big Four land drill¬ers have collectively laid off 40% to 50% of their year-end 2014 headcount, so there likely will come a point (i.e. after a couple hundred rigs return to work) at which labor limitations could put a cap on the pace of incremental rig additions.

“Our work suggests that 60-plus publicly traded U.S. onshore E&P operators will col¬lectively be working 44-plus incremental land drilling rigs (including ones currently term-contracted but which have been on standby mode) by year-end 2016, a nearly 10% uptick vs. the Baker Hughes U.S. land rig count of 470 (as of August 19).”

The firm noted that because the trough was so low, 380 rigs in May 2016, any percent¬age rig count increase now is going to look “astounding to the naked eye.”

Outrunning debt

Before any of this happens, and regardless of what commodity prices do through year-end, most E&P companies must continue repairing balance sheets. Reserve-based capital is going to be harder to come by in 2017 and it will cost more—and that line of thinking comes before one considers whether the Fed will raise inter¬est rates as it has been hinting at doing.

Even with a good oil price signal, experts warn that there is still enough lingering pain and uncertainty to go around as the E&P indus¬try must continue to manhandle billions of dol¬lars in debt (a lot of it coming due in 2017 and 2018, whether through Chapter 11 or not). A Houston Chronicle study this summer of 130 public energy companies indicated their com¬bined net debt—debt minus available cash—had soared to $440 billion in 2015 on the back of a decade-long shale binge, from $60 billion in 2005.
Capital may be tougher to obtain for some, but recent history shows if you want to do any kind of deal in the Permian Basin, the markets have your back. At press time, The Blackstone Group committed $1.5 billion to two start-ups in Midland, and Concho Resources Inc. had upped its position by buying a long-time private Midland company, Gary McKinney’s Reliance Energy LLC, for $1.6 billion.

As of June 2016, some $15.3 billion in new equity sales had been announced this year, and the majority of the 25 E&Ps that had closed offerings by that date outperformed their peers, Raymond James said. Finally, although in Jan¬uary U.S. junk-rated energy debt hit a two-de¬cade low, a few new bond offerings have been made, another signal the capital markets are opening back up.

Many investors were burned in the past two years, so their interest in energy now depends on the depth of their troubles, and whether they are focused on value or growth.

Guggenheim’s Chandra noted the market is selective. “A lot of the name-brand buyers in the big shale cycle pre the oil collapse are nowhere to be found now. Some of them just keep a placeholder like an ExxonMobil or a Chevron in their portfolio. They don’t want to figure out what the Delaware Basin is going to do—they don’t have the time—so they are saying, ‘As long as I have a Concho or a Pio¬neer, I’m good.’ This is a very picky market right now.”

TPH said in a research note that there appears to be “considerable headroom for increased energy equity capital participation and growth” as the recovery proceeds.

Although E&Ps have boosted their drilling and completion efficiencies measurably, they still have to wrestle with resource depletion and the spending to offset that, it said. “Main¬tenance and growth from here will require higher absolute levels of capital. Much of this we believe will be disproportionately funded by public equity.

“If the high-yield energy debt market car¬nage of the recent past and more reticent approach to bank debt are any indication, we don’t see that side of the balance sheet partic¬ipating at the last upcycle’s ‘high wire’ levels anytime soon,” TPH said. “And with a narrower recovery likely in store, new energy equity cap¬ital absorption capacity in areas investors want to be (e.g., Permian, completion services) will be sorely tested.”

Certainly companies going through restructuring will continue to be chal¬lenged. Buddy Clark, partner at Haynes & Boone, which has been tracking bankrupt¬cies since the downturn began, likens the recovery to a traditional 12 Step Program for alcoholics.

“The first step to recovery is recognizing the problem, so, I would have to say that yes, we’re well on the road to recovery,” he said. “More importantly, every bankruptcy is also a posi¬tive step to recovery, and we have had over 90 E&P bankruptcies since the beginning of last year. These have helped to right capital struc¬tures and realigned financial expectations—and they’ve instilled more discipline in the reorga¬nized companies and all of their stakeholders.”

But Clark cautioned that even in a recovery, more bankruptcies among producers and oilfield service companies may lie ahead, because, “You can’t repay $100/bbl debt with $50/bbl oil.”

He explained, “This fall’s borrowing base redetermination season coincides with the end of last spring’s borrowing base deficiency amortization period. I expect to see lenders continuing to want to ‘kick the barrel down the road,’ where they can find sufficient credit justification, but there will be some companies that have reached the end of the road.”

Opportune’s Baggett concurred, saying several companies in distress that have not yet filed for bankruptcy will likely have to do so in coming months. “When you have less capital and a depleting asset, that’s not a good combination.”

Based on his experience (and as he affirmed by talking to other firms that help companies work through restructuring), Baggett said the No. 1 problem on everyone’s checklist is denial. “After all, to get into this business you have to be an optimistic kind of person. It’s in their nature to believe things will get better, until they don’t.”

Shaia D. Hosseinzadeh, man¬aging director and head of energy and natural resources, WL Ross & Co., shared his sentiment. “Even with the recent spate of restruc¬turings that have occurred,” he said, “leverage levels remain at record highs across the sector. Without a large move in oil, many E&Ps will not be able to outrun their debt.

“The fallout in credit now also means that companies will need to be creative about finding new financ¬ing sources. Banks are retrenching under the weight of regulation, and the high-yield market has become selective.”

Chandra reminded us that a resource company by its very nature cannot shrink its way to pros¬perity. He expects more acquisitions to come because dollars are not being used to drill.

“Tens of billions of dollars are going to be diverted to debt reduction, but as we get into 2017, it’s not going to be about debt so much anymore, but about inventory. SM Energy’s entrée into the Delaware is a marquee example.”

The future is here

General consensus is that while the stun¬ning advances in technology will mean that some efficiencies and cost savings are sus¬tainable throughout the oil patch, the cost to drill and complete a well must inevitably rise again. It is that tricky balance between operating costs, debt service and income that can bedevil even the most experienced CEOs.

Higher oil prices, say $50 to $60, will encour¬age more drilling.

“I think this could be deemed a recovery for the highest-caliber E&Ps, and that puts you smack dab in the Permian,” said analyst Mike Kelly of Seaport Global Securities. “I do feel the worst is behind us, but everybody has to clear $50, and we’re not there yet.” The firm is calling for $51 in 2017.

Kelly said the weighted average proj¬ect returns since the downturn began have recovered by 20% for his coverage universe, mainly due to oft-mentioned cost savings and improved drilling methods. Completion advances and well productivity gains are also factors.

“The good news is that, ultimately, a few could make money at $60 and now almost everybody can. The new question is, who can make money in a $50 world?”

Cowen & Co.’s Charles Robertson said in a report that we will see the supply-demand bal¬ance in second-half 2017. “We wouldn’t expect significant price inflation until another 100 rigs are added, as E&Ps are currently seeing about $16,000 per day for ‘high-end’ rigs. On the completions side, operators are seeing flat to slightly lower pricing.”

In an August meeting between Core Lab man¬agement and RBC Capital Markets, the com¬pany told analysts that producers would need $60 to $75/bbl oil, and as many as 1,200 rigs working for 18 months, to stabilize domestic production at year-end levels. That’s a far cry from the nearly 500 or so rigs working today.

The effects of a slower drilling pace on pro¬duction—and producer incomes—will continue to play out through 2017 and color the outlook for the recovery. Half of all the rigs that are still drilling are in Texas, where Lone Star well permits and completions tell the story. In August 2016, the Texas Railroad Commission processed 545 oil and 223 gas completions, compared to 1,113 oil and 172 gas completions in August 2015. Texas well completions year to date totaled 8,107, down from 14,665 during the same period in 2015.

At the same time, many E&Ps are adding a rig or two now, or said they will consider it as the year winds down. They laid out multiple sce¬narios in their second-quarter conference calls; the takeaway seems to be that everyone is still touchy and trying to remain within cash flow.

As for the demand for midstream services if E&P customers keep drilling at a slower pace, “I don’t see any real recovery until 2018,” said Justin Carlson, vice president of research for East Daley Capital, in Centennial, Colorado. “That’s when it starts to be inter¬esting in terms of demand for our product [midstream services].”

The future will depend on supply metrics in the U.S. and globally, as over-supply has been the main problem blocking a sustained rally in oil prices. Production declines will likely abate soon, as operators complete their drilled but uncompleted (DUC) wells and send a few more rigs back to the field.

“The story for 2017 may prove to be less about economic activity and consumption (though the demand side of the ledger remains key) and more focused on supply deliverabil¬ity,” the CSIS report said. “Non-OPEC supply, including in the U.S., is slated to decline both this year and next. Any measurable increases in consumption will have to come from either stock (inventory) depletion or new volume from OPEC sources.

“Looking longer term, we are definitely headed for a day of reckoning for which we seem ill prepared today—and one only aggra¬vated by calls for halting all new investment and keeping viable fuel resources in the ground.”

Guggenheim analysts argue that completing DUCs will not threaten supply or a price recov¬ery, although they could offset the production decline underway, because companies are wor¬ried about efficiency losses if they add rigs and completion crews.

Kelly reiterated this, saying that given the new efficiencies, E&P companies will be leaner than ever and more capable of generat¬ing returns at lower prices.

All things considered, we take heart in some¬thing we heard at Hart Energy’s Executive Oil Conference in Midland in November 2015, when Diamondback Energy CEO Travis Stice cited his oilman grandfather, O.W. Stice, who used to say this: “Learn to saddle up in the dark so when day¬light comes, you’ll be ready to ride.” We’ll take that advice as the recovery proceeds.

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