The long slide of West Texas Intermediate (WTI) to $80 per barrel (bbl) has weighed on energy companies and cast a cloud of uncertainty over future activity levels. The main question that investors are asking relates to capex plans. Will exploration and production (E&P) companies cut spending, and if they do, when, and by how much?

Like many economic scenarios, there is no single answer. Budgets will depend on the strength of companies’ balance sheets, the individual basin economics in which E&Ps are operating, planned exit strategies and so on. And, to a large extent, 2015 capex plans will depend on the as-yet unknown depth and duration of the current commodity price swoon.

For larger E&Ps—many of whose managements have weathered such downdrafts in crude prices in the past—there is a greater likelihood of staying the course, especially for those with operations centered in the core of key basins. Smaller E&Ps might be less resilient, given a smaller production base from which to seek economies of scale and generally higher financing costs. For these, debt levels and quality of acreage positions carry heightened importance.

For investors, there is a natural focus on E&Ps meeting growth targets and building net asset value (NAV), but with the concurrent caveat of not unduly stretching balance sheets. In adjusting to the steep drop in commodity prices, this might create a paradoxical—almost no-win—tension for E&Ps.

“We on Wall Street like to talk to E&Ps about financial discipline,” said one veteran observer of the oil and gas industry, “but when they don’t show growth, we penalize them heavily. In many respects, they are in a no-win situation.”

Early reads

So what is the early read on activity levels—and capex—projected for 2015 in the wake of pressure from falling crude prices? And what price thresholds would prompt a change in activity if transgressed?

Opinions vary as to precise price levels and timing, but a common sentiment is that crude oil would have to stay at lower prices—and for longer—before companies would meaningfully reduce activity. Price levels likely needed to bring about such a change are cited as at or below $80/bbl (Tudor, Pickering, Holt), $70/bbl to $75/bbl (J.P. Morgan) and $65/bbl to $75/bbl (Barclays).

Robert W. Baird & Co. emphasized the importance of the duration of low crude prices. Larger E&Ps expect “to evaluate capital budgets if crude drops and stays below $85/bbl, with activity curbed on a sustained pullback below $80/bbl,” Baird analysts said.

From the oilfield service sector, taking a similar view is Baker Hughes’ CEO, Martin Craighead, who said crude oil prices would have to stay low “for a couple of quarters” to move certain customers to the sidelines. “There is no indication that these folks are going to abate or slow down,” he said on the company’s third-quarter conference call. For E&Ps in core areas, “I think $75 is the starting point for where activity starts to slow.”

For E&Ps, the good news is that they have made significant progress in bringing down the cost curves in many of the unconventional plays, thereby helping to protect the plays’ economics. According to a Barclays report, for example, “recent disclosures suggest full-cycle supply costs may have fallen by roughly $10/bbl due to enhanced completion techniques.”

Similarly, Morgan Stanly cited ongoing drilling and completion optimizations, coupled with improved EURs, in its assessment that the cash prices needed to break even in U.S. unconventional plays have fallen by up to $30/bbl since 2012. As a result, said Morgan Stanley, “many U.S. unconventional plays are no longer ‘the marginal barrel.’”

Findings from a Robert W. Baird study that focused on the marginal cost of U.S. crude oil production point to a weighted average marginal cost of U.S. crude of around $73/bbl. The study incorporated data from 17 plays, weighted by the number of rigs operating in each play, as well as rigs operating in other areas. Breakeven costs, assuming a minimum 20% internal rate of return (IRR), ranged from $53/bbl in the liquids-rich Eagle Ford to $93/bbl in the Barnett Combo play.

In a study by Robert W. Baird & Co., breakeven costs, assuming a minimum 20% IRR, ranged from $53/bbl in the liquids-rich Eagle Ford to $93/bbl in the Barnett Combo play.

If the WTI price were to average $85/bbl, the economics of the three “core oil plays”—the Eagle Ford, Bakken and Permian—“are still robust,” the study’s authors said, noting that the weighted average marginal cost of production for the latter plays was about $70/bbl.

The Baird analysts offered a less optimistic outlook for smaller E&Ps, however, particularly those with less financial flexibility and fewer core acreage positions. These companies risk seeing their cash flows impacted more quickly because of higher leverage, minimal economies of scale and longer paybacks on wells, among other factors. The result is less capital available for immediate reinvestment.

“While all E&P cash flows get impacted in a lower commodity price environment,” the Baird report said, “the smaller ones will likely blink first and reduce activity well before their larger peers with economies of scale and top acreage.”

While smaller E&Ps might be more at risk in the initial phase of a commodity price downturn, a wider sweep of E&Ps would likely be affected in the event of a more protracted slump, increasing pressure on balance sheets throughout the sector.

The impact of declining discretionary cash flows relative to projected capital budgets is a focus of research by Simmons & Co. International. It compares drillbit capex as a percentage of discretionary cash flow estimates to arrive at E&Ps’ drillbit capex ratio, a measure of their outspend or underspend.

With recently sliding commodity prices, Simmons’ 2015 forecast of the drillbit reinvestment ratio for E&Ps under coverage rose to 114% (prior: 108%), based on a commodity price deck of $86.70/bbl for WTI and $3.87/Mcf for Henry Hub natural gas (prior: $91.26 and $3.94). For perspective, the drillbit ratio for 2014 is projected to be 111%, while the average for 2008 to 2013 was 108%. The drillbit ratio during the latter period has ranged from a low of 89% in 2008 to a high of 128% in 2012.

Downside sensitivity

In testing downside sensitivity, Simmons said that under “a more somber, but plausible” commodity outlook for 2015 of $80/bbl and $3.50/Mcf, the drillbit ratio would increase to a high near 126%, a level “suggestive of strain on the industry.” This scenario would be plausible in that “it does not set a new precedent for E&P capital outspend.” But under such a scenario, Simmons said it “would not be surprised if E&Ps choose to restrain spending.”

In a subsequent report, Simmons said a reasonable assumption is for E&Ps to be “cautious” in setting 2015 capital budgets. In addition to the likelihood that “long-term investors will be pushing for E&P management teams to keep capital programs within cash flow,” Simmons said E&Ps would face several obstacles to securing financing. These include an asset divestiture market that is likely to be “tepid,” an equity window that is “closed” and a debt market characterized by “unfavorable high-yield spreads.”

But what if the dramatic slump in E&P stocks—the EPX index is down about 25% from the end of June through the end of October—augurs just the early stages of a crude oil collapse, which a dysfunctional OPEC allows to continue sliding as key members prioritize market share over price? If rebalancing world oil markets requires a flattening—or an elimination—of U.S. oil growth, what does that imply for levels of U.S. capex and production?

Simmons offers two scenarios. If activity is held in line with current assumptions, 2015 oil production is forecast to grow on the order of 1.1 MMbbl/d, a level exceeding global demand growth that is projected at about 1 MMbbl/d, based on 3% to 3.5% global GDP growth. This would contribute to an oversupplied world market in the short term, although U.S. oil production growth is projected to moderate to a rate of 0.7 MMbbl/d in 2016.

A second scenario assumes activity is reduced by 30% in order to contribute to a flattening in U.S. oil supply during the second half of 2015—albeit still up by 0.7 MMbbl/d vs. a year ago—and results in growth of only about 0.2 MMbbl/d in 2016. In the short term, this would do little to redress the global supply imbalance, but could sow the seeds of a later oil market recovery, according to Simmons.

“While this downside case would provide some reduced 2015 supply growth, it would do little to bring global supply and demand into balance near term,” the Simmons analysts said. “However, this extreme reduction in activity would result in a sharp deceleration of growth during 2016, of only 0.2 MMbbl/d, contributing to a rapid global supply shortage one year out.”