As Yogi Berra famously quipped, “It’s tough to make predictions, especially about the future.” But it’s not hard to say that 2015 is off to a very tough start for oil producers, who saw the prior-year price for West Texas Intermediate (WTI) tumble by almost half over the course of six months.

The magnitude and speed of the collapse—exacerbated by Saudi Arabia’s abdication of its traditional role as OPEC’s swing producer—leave E&Ps variously striving to retrench, refocus and, in some cases, simply survive. Balance sheets will be scrutinized, and a number of small- and mid-cap names may well face liquidity issues in the year ahead unless crude prices rebound.

Capex programs are being slashed, in many cases up to 20% to 30% year-over-year, as E&Ps seek to minimize cash flow outspend or pare back to within cash flow based on the most recently lowered price deck. Forecasts of rig count reductions fall routinely. Within three weeks, for example, commentary by Tudor Pickering Holt shifted from a base-case scenario of more than 500 rigs being let go at an assumed $70/bbl WTI price to a possible scenario of 800-plus rigs released if oil stays below $60/bbl.

Analysts have focused on several themes. One is the degree to which growth of U.S. liquids production—mainly from unconventional plays—has to slow down to help rebalance global demand and supply in the absence of action by OPEC. Another involves identifying those E&Ps that, based largely on size and balance-sheet strength, are better equipped to handle the recent commodity downdraft. A third is the prospect for M&A.

Hindsight, of course, illuminates how such conditions came to prevail in the oil market. Yes, unconventional production in the U.S. was—and still is—on an upward trajectory. But it coincided with a resurgence in production from Nigeria and, especially, Libya, which some estimate to have added nearly 1 million barrels per day (MMbbl/d) to world markets over a three-month period.

Other factors include Saudi Arabia’s battle to maintain market share in Asia at a time when worldwide crude demand estimates were being revised significantly lower. And, importantly, currency markets have been driving the U.S. dollar higher. Noting the inverse correlation between crude prices and the dollar, Raymond James & Associates said more than 70% of crude’s move lower since it peaked last summer could be attributed to the dollar’s rise.

How bad will this “perfect storm” prove to be? How must key factors change for E&Ps to weather the storm? And are oil prices approaching a bottom?

Raymond James has been bearish on crude for the past couple of years—a call that, early on, proved premature due to repeated geopolitical events disrupting global supplies.

“Over the last two years, when we first came out with the call that oil was going to $65/bbl, people would look at us as if we had three heads,” recalled Andrew Coleman, managing director of E&P research for Raymond James in Houston.

With near-term growth in global supplies seen outstripping demand, assuming no cutback in OPEC production, the firm is cautious—but turning more optimistic—on the outlook.

“It’s hard to call a bottom,” Coleman said. “We haven’t seen production growth begin to decline; we haven’t seen OPEC do anything; and it’s hard to imagine that the demand side snaps back to solve the problem overnight. However, while the OPEC meeting last Thanksgiving feels like a long time ago, and with WTI dropping below $50/bbl, we are optimistic that oil could bottom in the first half of this year, given the dramatic cutbacks in capex we are seeing from the industry.”

Led by research director Marshall Adkins, the Raymond James energy team has tackled the near-term oversupply issue by attempting to solve for two questions. The first: How much does U.S. oil supply have to slow to balance the global equation? The other: How low do oil prices need to fall to balance the global oil market?

With WTI dropping below $50/bbl, "we are optimistic that oil could bottom in the first half of this year, given the dramatic cutbacks in capex we are seeing from the industry," said Andrew Coleman, managing director, E&P research, with Raymond James in Houston.

Key assumptions are that OPEC production remains near current levels (excluding NGL growth), while growth in global oil demand rises modestly to a rate of 1.1 million bbl/d per year. Long lead-time projects, including offshore projects, are assumed to remain relatively robust, as substantial sunk costs typically dictate spending should continue in the face of short-term oil price volatility. As a result, short-term, cash-flow-driven projects in the U.S. unconventional sector are projected to bear the brunt in terms of “right-sizing” global production.

Under these assumptions, the Raymond James findings are that the current U.S. growth rate of liquids production—estimated at about 1.5 MMbbl/d currently—must decelerate to near zero over the next 18 months. And the price signal required to achieve such a slowdown in output is estimated to be about $65/bbl.

These findings reflect an assumed 35% reduction in E&P capex in 2015 and a 40% drop in total capex from peak to trough. In turn, this is projected to result in more than 700 rigs being released in 2015, with the average rig count for the year showing a decline of about 540 rigs versus 2014. For 2015 and 2016, the firm’s price deck assumes WTI prices of $62/bbl and $75/bbl, respectively, and natural gas prices of $3/Mcf and $3.55/Mcf.

If these projections prove correct, Raymond James forecasts that U.S. production growth this year will slow to about 800,000 bbl/d. Furthermore, with growth in U.S. production projected to grind to a near halt in 2016, the firm forecasts global oil demand and supply coming into balance toward the middle of next year.

Assuming ongoing annual demand growth of more than 1 million bbl/d, and given the lagging nature of production responses, “that means world oil markets would likely be undersupplied in 2017 if oil prices remain anywhere close to current spot prices,” according to the firm.

A transitional year

At Simmons & Co. International, the research team projects the initial stages of an improving supply picture for the second half of 2015, but doesn’t downplay the pressures expected from excess supply peaking in the second quarter. Global oversupply is estimated at roughly 1 million bbl/d in the first quarter, growing to about 1.5 MMbbl/d in the second.

"This is very much a transitional year, with a cathartic response in the first half that could support rehabilitation and potentially capital investment in the second half of the year or into 2016," Dave Kistler, managing director and co-head of research at Simmons & Co. International, said.

“The outlook for 2015 is challenged,” Dave Kistler, managing director and co-head of research at Simmons, said. “There’s no doubt there is oversupply; there’s no doubt there are demand issues. This is very much a transitional year, with a cathartic response in the first half that could support rehabilitation and potentially capital investment in the second half of the year or into 2016. I think investors have to gain confidence that crude has bottomed and is poised for recovery.”

The time needed for energy to gain its footing, however, is not expected to be a multiyear process. A deceleration in the rate of U.S. oil growth will likely mark a turning point, which Kistler anticipates around the “tail end of the second quarter” of this year.

“We think this cycle fixes itself over quarters, not years,” said Kistler. “And we think it fixes itself over quarters, not months.”

Simmons’ model for U.S. oil production growth assumes a 25% reduction in E&P capex this year, with roughly a commensurate drop in the rig count as the aggregate fleet falls by some 150 rigs each quarter. At the same time, it is factoring in gains of as much as 20% for both well productivity as well as efficiency gains, as E&Ps focus on drilling the best wells in the core of their acreage and shaving more days off spud-to-sales times. Importantly, this analysis was prepared when calendar 2015 futures were $67/bbl and natural gas futures were $3.80/Mcf. With the continued decline in forward prices, rig count cuts could be even more pronounced.

The result is that growth in U.S. oil production is projected to slow to just more than 900,000 bbl/d in 2015, down from the prior-year rate of 1.1MMbbl/d. Moreover, if measured by the December 2015 exit rate versus the prior year-end exit rate, the rate of increase falls further to 680,000 bbl/d. Holding the rig count flat for next year, the pace of growth drops to a little more than 350,000 bbl/d in 2016, while the December year-over-year exit rate declines to about 290,000 bbl/d.

Provided global oil demand remains relatively robust in 2015 and 2016, growing at an annual rate of about 1MMbbl/d per year, Kistler anticipates rising visibility of an improving crude market next year. “If people can project a tighter market in 2016, they’ll be more confident in saying, ‘Crude is going to have to get better to incent producers to drill.’”

As to the timing of crude bottoming, much will depend on whether commodity markets put greater credence in the falling rig count, offering earlier visibility, or the more tangible data afforded later by a deceleration of production growth. “Maybe we bottom in the first half of this year, if people follow the rig count. If they have to wait to see slowing growth in production, it could be the middle of the year.”

Longer this time?

Morgan Stanley managing director Evan Calio draws a distinction between the current and previous downturns in oil, a distinction that poses “greater risk that the current down cycle is of longer duration.”

"I think it will be a much more active downturn. Companies will understand their resource base and they know what they want," Morgan Stanley managing director Evan Calio said.

Historically, it has been the onset of a recession that has typically driven demand out of balance with supply, noted Calio. By contrast, the current downturn stemmed only partly from demand and was to a large extent due to growth in North American supply and a change in OPEC oil market policy.

“We’ve ended a cycle in energy. If you take the Saudis at their word that they will leave it to market forces to take barrels off the marketplace, rather than the cartel, I don’t see it clearing in 2015,” said Calio. “If I look to 2016, I can see the imbalance clearing up.”

Calio did not rule out further pain in crude oil prices. In an oversupplied market—such as expected during the first half of this year, especially while refineries undergo maintenance—prices have been known to drop to cash cost levels that are “in the $40s” for Brent. “All things being equal, we could easily visit those levels,” he warned. “However, if oil prices remained at cash cost for some time, this would accelerate the clearing process into the second half of 2015.”

In his large-cap sector, Calio expects capex cuts of around 30%, slowing production growth in 2015 to 600,000 to 700,000 bbl/d. Some of the early cuts are likely “premature” and subject to further downward revision in February and March, he said. Preserving cash makes sense: “You aren’t likely to get credit for 7% growth versus 5% growth in a down cycle,” he observed.

In terms of stock selection, analysts are quick to distinguish between E&Ps they frequently divide into the “haves” and “have-nots,” with many of the former comprised of larger-cap names offering defensive qualities needed in the markedly lower commodity price environment.

In regard to large-cap names, Calio focuses on two main recommendations: Noble Energy Inc., a high-quality name he said has seen the most relative multiple compression, and Occidental Petroleum Corp., offering a combination of dividend and growth. Anadarko Petroleum Corp. also is rated outperform, while EOG Resources—viewed as “a phenomenal company”—was recently lowered to equal weight after appreciating to a two-multiple premium to its peers and thus leaving only “muted” upside.

Names favored by Simmons’ Kistler are Anadarko Petroleum Corp. and Devon Energy Corp., among larger-cap names, and Pioneer Natural Resources Co. and Diamondback Energy Inc. for investors with “more adventurous appetites.”

Like other analysts, Kistler has steered away from many of the higher-leveraged, smaller-cap E&Ps.

“Of the E&Ps that I cover, those that have debt-to-EBITDA of three times, either currently or projected to be at those levels, have been some of the worst-performing equities,” he said. “People have liquidated positions either for fear of them not being able to raise funding or having to cut capex so drastically that they deliver zero growth and potentially declining cash flows on a year-over-year basis.”

Survival mode

The Wells Fargo research team, led by senior analyst, David Tameron, sees its E&P universe broadly grouped into two categories.

One is comprised of larger, better-capitalized companies for whom 2015 is “a year of transition” in which the pullback in capital is used to refocus, high-grade drilling programs and put in place measures to set themselves up for a more productive 2016. The other group, made up of mostly small-cap and some mid-cap names, will be preoccupied with a singular goal: “survive and advance.”

For those in the latter camp, “you’re just trying to survive the cycle,” Tameron said. “I don’t know if you’ll see companies go bankrupt, but some could disappear through consolidation, either voluntary or involuntary. Unless crude moves significantly higher, we believe there will be significant industrywide pain before the industry rights itself. There are definitely small- and mid-cap names that are going to stretch their balance sheets.”

After the OPEC meeting late last year, the Wells Fargo team pared back its list of outperform-rated stocks, lowering ratings on more than a dozen E&Ps to market perform in the wake of the Saudi-led decision to hold OPEC production unchanged.

“If you’re Saudi Arabia, I don’t know why you would put people through this much pain and then pull it back just a couple of months later,” said Tameron. “I don’t think they are in a hurry to reverse.”

"Some small-cap companies believe that if they can't grow as a public company in the small-cap sector, they might as well be private," David Tameron, managing director, Wells Fargo, said.

Those E&Ps retaining an outperform rating from Wells Fargo in the large-cap sector are Anadarko, Devon, EOG Resources and Pioneer; in mid-cap, Cabot Oil & Gas Corp., Concho Resources and Diamondback Energy Inc.; and in small-cap, Carrizo Oil &Gas Inc., PDC Energy Inc. and Rosetta Resources Inc.

Relative to the energy sector selloff in the 2008-2009 financial crisis, higher-quality names have stood out for being more resilient, Tameron observed. “Quality has held up a lot better. You’re seeing a lot more discernment this time around. Investors are not saying, ‘Get me out of all energy. Instead, it’s get me out energy that is higher cost or that is more of a marginal structural play.’”

Tameron expects the E&P sector to undergo structural changes, particularly in re-aligning costs, during 2015. The firm’s energy team projects capex cuts of 20% to 25%, resulting in 600 to 650 rigs being released this year. And risk of further downside in oil prices may still lie ahead.

“I think we go lower before we go higher,” said Tameron, adding that he wouldn’t rule out oil prices dipping—temporarily—into the $40s. “And we need to get back to the $70s to not see a dramatic drop in the rig count.”

The feedback from some E&Ps is they would prefer to cut back spending early in the year, leaving them potentially in a position to consider adding rigs in the latter part of 2015 if commodity prices allow. With many E&Ps’ output projected to be flat, if not down, from fourth-quarter 2014 to fourth-quarter 2015, this could set them up to return to growth in 2016, Tameron noted.

How important is it to show growth in a deeply depressed commodity environment?

“Some small-cap companies believe that if they can’t grow as a public company in the small-cap sector, they might as well be private,” Tameron said, echoing comments made by some E&Ps at the Wells Fargo energy conference late last year.

A wide delta

Mike Kelly, senior analyst with Global Hunter Securities, also divides his E&P coverage into two camps, highlighting the better performers as ones able to “survive and thrive” in a lower oil price environment.

Whereas virtually all E&Ps had a growth story at $100/bbl, “you’ll see a pretty big delta between top performers and bottom performers” in the sub-$60/bbl oil price environment accompanying the start of 2015, Kelly said. And away from those that can “survive and thrive,” there are other E&Ps with lower-tier acreage and economics “that will have to change their stripes or, frankly, go away.”

As an example of an E&P switching strategies under pressure from the lower oil price environment, Kelly cited Comstock Resources’ announcement late last year that it was suspending its oil-directed drilling in the Eagle Ford. Plans called for two of four rigs to be released early this year, with the remaining two rigs being relocated to north Louisiana for drilling on the company’s Haynesville natural gas properties.

With the combination of lower capex and reductions in the rig fleet, Kelly anticipates a slowing in oil production momentum late in the third quarter or early in the fourth quarter of this year, although he is quick to point out that efficiency gains in the U.S. “can’t be ignored.” For example, Concho Resources recently reported a 75% increase in average cumulative production over the first 180 days as a result of enhanced completion techniques used in its Northern Delaware Basin wells, he noted.

Once short-term supply and demand come closer to equilibrium, Kelly leans towards a WTI price band settling out around $60 to $70/bbl, in between two markers.

“At $80/bbl, we’ve proven that we can tip the scale of supply and demand through these prolific shale plays in our backyard,” he said. At the other end, “if you look back to 2008-2009, it was about $50/bbl that stocks got disconnected from the oil price. Oil continued to go down, but the stocks didn’t follow. That’s what we’ve been looking for as a ‘buy’ signal for the bottom.”

And what names are to be bought on the “survive and thrive” list?

In larger-market-cap names, Continental Resources Inc. and Concho Resources are favored, as well as the more gas-weighted Range Resources Corp. In smaller-cap names, picks are Diamondback Energy, Carrizo Oil & Gas Inc. and Synergy Resources Corp.

Stock selection for Raymond James’ Andrew Coleman also focuses on some smaller-cap names on the oil side: favored are Oasis Petroleum Inc. and Bonanza Creek Energy Inc. In larger-cap names, he prefers defensive names with good balance sheets: Anadarko Petroleum, EOG Resources and QEP Resources Inc.

For most analysts, the collapse in crude prices provides at least a basis for discussing the potential for increased M&A amid the now markedly lower-priced E&P sector.

Oasis Petroleum is viewed by Coleman, for example, as “as a great operator that’s been beaten down in the sell-off and whose top-tier Bakken land position also makes it an attractive take-out candidate.” Potential buyers might be an E&P in the Bakken looking to add size and scale or a large-cap player looking to enter the basin. For the E&P sector as a whole, however, Coleman does not see acquisitions as a major factor in view of likely challenges in accessing debt and equity markets to secure funding. In addition, he sees little likelihood of the majors emerging as potentially large acquirers in the current downturn.

Morgan Stanley’s Calio expects the large-cap E&Ps to be prudent in maintaining balance-sheet strength, but is optimistic about a pickup in M&A activity, assuming the right opportunity arises.

“I think it will be a much more active downturn. Companies understand their resource base and they know what they want,” Calio said. “You hear of a lot of companies that want to be acquisitive and use this downturn to add another core area of operations. You want to preserve cash and balance-sheet strength so you have more opportunity in a downturn.”

There have been 1.6 MMbbl/d of recent deferrals and cancellations of projects expected to contribute to global supply over the back half of this decade.

After its restructuring moves and the spinoff of California Resources Corp., Occidental Petroleum Corp. could be expected to use its “war chest” to make acquisitions, according to Calio. Hess Corp. could also be viewed as a “natural consolidator,” in his view, while other potential acquirers could be Exxon Mobil Corp., Chevron Corp. and Marathon Oil Corp.

Simmons’ Kistler suggests it’s quite possible that consolidation may take place within basins, as larger independents take over their smaller peers that may be struggling in areas the acquirers particularly like. And although not suggesting it may be imminent, he doesn’t exclude the possibility of certain major oil companies acquiring “pure play” E&Ps. In the Permian, potential targets might be Pioneer Natural and Concho Resources, as well as “marquee” names like Diamondback Energy and RSP Permian Inc. In the Bakken, Oasis Petroleum and Whiting Petroleum Corp. could be targets.

A key caveat is that “sure, consolidation makes sense, but the majors have not led the way in shale development,” said Kistler. Given the independents’ lower cost structure, any acquisition would likely be allowed to operate under a separate umbrella, as with ExxonMobil’s purchase of XTO Resources.

But amid all the talk of falling commodity prices, reduced capex and possible need for consolidation, what factors could come to the fore and surprise to the upside—and maybe shorten the duration and depth of pain from low oil prices?

Simmons’ Kistler points to the potential for delays, cancellations or execution issues related to the backlog of major projects planned in non-OPEC countries. With a nameplate capacity of 10.8 MMbbl/d, covering 2014-2018, the projects are skewed heavily to Brazil and Russia—countries where “execution risk is above average”—which account for roughly 30% and 15% of the backlog, respectively. Moreover, some 1.6 MMbbl/d of the 10.8 MMbbl/d of project backlog have already been deferred or cancelled.

In addition, there is always the possibility of unplanned outages in countries such as Iraq, Iran, Libya, Nigeria, Russia and Venezuela. Also, sanctions imposed on Russia could ultimately result in reduced oil output there, while the competing demands of social programs—historically financed by higher oil prices—could squeeze capital available for reinvestment in oil in a host of countries in the Middle East, North Africa and Latin America.

“We can’t recall a more unstable period in the world order in our lifetime,” said a recent Simmons report, “and the implosion in oil prices is a potential accelerant to an already incendiary Middle East-North Africa region, in addition to Venezuela, Russia and other global cauldrons. Notwithstanding, we would submit that there is zero geopolitical risk premium currently embedded in oil prices.”

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