But a few low-cost, low-leverage E&P companies remain undervalued, despite looming commodity headwinds.
By Dave Meats, CFA | 09-13-17 | 06:00 AM | Email Article

Crude oil fundamentals look healthier than they’ve been for years, largely thanks to voluntary curtailments from OPEC and its partners. By giving up 1.8 million barrels a day, this group has engineered a supply shortage to realign global inventories with the long-term average before the cuts expire in March 2018. But the decline will be short-lived if the cartel restores full production after that, as we expect in our base case. The alternative--another extension--is risky for the cartel. It would encourage additional growth from rivals, like the United States, that are willing and able to fill the void. So even if full compliance can be assumed--hardly a foregone conclusion--then extending the cuts again only kicks the can down the road.

David Meats, CFA, is a senior equity analyst for Morningstar.

Prolific growth from low-cost unconventional resources is the biggest obstacle for traditional producers like OPEC. The recent downturn galvanized shale companies in the U.S. to cut costs and learn to live with lower prices. As a result, the muted oil price recovery we’ve seen thus far was sufficient to justify a strong ramp-up in drilling activity. The U.S. horizontal rig count remains well below the 2014 peak, but as a result of remarkable advances in efficiency and well productivity, it is already high enough to drive very strong growth for several years. Therefore, next year’s output is likely to exceed the call on U.S. shale. But the industry can’t react quickly when it recognizes the danger. Many of its rigs operate under fixed-length contracts with steep termination penalties. And when the rig count does decline, there will be an additional overhang related to the lag between drilling a well and bringing it on line.

Consequently, our midcycle forecast for $55 a barrel West Texas Intermediate is below many sell-side estimates. But we don’t think the market is giving enough credit on the cost side, either. Contrary to conventional wisdom, there’s still plenty of scope for further improvements in efficiency and productivity, at least partially offsetting the likely reinflation of service costs. That means a handful of exploration and production stocks--with high-quality (low-cost) acreage and low financial leverage--still look attractive for long-term investors, even after factoring in our gloomy commodity outlook.  RSP Permian fits this mold.

Fundamentals Deteriorate When OPEC Cuts Expire
Oil market fundamentals right now are in the best shape they’ve been for years. After a string of large inventory builds in 2015-16, demand has finally caught up with supply, and until the onset of Hurricane Harvey, substantial inventory draws were occurring. The impact of the hurricane on oil stocks is likely to be transitory, and further draws are expected before the end of 2016. This perceived tightness is artificial, as it stems from large production cuts by OPEC and other significant producers, like Russia. These temporary cuts are withholding 1.8 mmb/d from the market; if they expire as scheduled after March 2018 as we currently expect them to, then another bout of painful oversupply is likely.

The production cuts were originally set to expire at the end of June 2016, but the cartel chose to extend them by nine months because they are working, albeit more slowly than originally anticipated (we believe a seasonal dip in demand in the first quarter of 2017 is partly to blame for the slow start). Key OPEC ministers have stated publicly that they are committed to realigning global crude stocks, which are currently brimming, with the industry’s five-year average. The draws we forecast in 2017 will narrow the gap considerably.

However, inventories are unlikely to remain long near this normalized range if the March 2018 expiration for the cuts is not changed. The additional volumes generated if OPEC and its partners return to full production next year, coupled with increasing U.S. shale production, would probably throw crude markets back into oversupply, pushing inventories well above the typical range again. Therefore, we see little scope for crude prices to strengthen from current levels. Our 2018 forecast for WTI is $45/bbl.

Further Cuts Plausible, but Compliance Could Waver
The key risk to our near-term forecast is that OPEC decides to surprise the market with another extension. In a vacuum, that would make sense--the market showed a $6/bbl (14%) hike following the initial cut announcement, which far outweighs the volumes lost (1.8 mmb/d, or about 5%-6%). Even if the true “premium” resulting from extended cuts is only $1-$2/bbl, participating producers would still be better off, at least in the short run.

Saudi Arabia, which is seeking a $2 trillion valuation for state-run oil company Aramco ahead of next year’s initial public offering, has a particularly strong incentive to pursue higher crude prices. It has agreed to curtail its own production by 0.5 mmb/d, which is about 30% of the total OPEC cut. But it isn’t likely to act alone, and others in the cartel may be less willing to sacrifice share indefinitely. Many OPEC countries rely heavily on crude revenue to balance their budgets, fund social programs, and enable costly fuel subsidies. The result is the prisoner’s dilemma: There is a temptation for individual countries to rely on partners to enact the cuts and prop up prices while “cheating” themselves. Therefore, even if the cuts are extended officially, compliance (which was uncharacteristically strong in the first half of the year) could waiver. In this cheating scenario, the volumes actually withheld from the market would taper off gradually during the cutting period, reducing the impact of the initiative on inventories.

OPEC has attempted to support crude prices by controlling supply several times in the past, often successfully. However, the strategy works best for downturns triggered exclusively by weak demand, often related to the general economy. In the early 1980s, the industry was forced to contend with major supply additions as well, from Alaska, the North Sea, and the Gulf of Mexico. These new discoveries were prompted by a prolonged period of high prices during the 1970s oil crisis, when developed countries faced acute shortages (analogous to today’s glut, which was driven by the shale renaissance that stemmed from consistently high prices during 2010-14). OPEC’s efforts to prop up crude prices failed spectacularly--the cartel’s share of world exports fell from 40% to 30% over 1980-85 but oil prices registered losses every year anyway and declined 60% in total over the period.

Therefore, even if the cuts are extended next year, they are unlikely to have a big impact. History shows that curtailing production is an ineffective strategy with prolific new supply, and in this case, U.S. producers are willing and able to increase volumes to fill the gap.

U.S. Supply Surge Inevitable, Even If No Additional Rigs Are Activated
Shale growth is the main component of the glut we anticipate after March 2018. Huge growth in that arena is near certain next year, and this onslaught of new production will probably coincide with the potential expiration of OPEC’s voluntary curtailments, overwhelming crude markets once again.

The precipitous plunge in global crude prices that began late 2014 and continued through the following year wreaked havoc on most shale companies’ finances, forcing them to curtail their operations. The U.S. horizontal rig count collapsed roughly 70% from peak to trough, and output eventually declined as well (production from major shale plays fell to 5.1 mmb/d from 5.7 mmb/d). The industry responded quickly with dramatic cost cuts and substantial productivity gains, resulting in significantly lower break-evens. As a result, many E&P companies found that by early 2016, even though crude prices had only partially recovered, it was economically favorable to add rigs and accelerate drilling.

The industry appears to have overextended itself following this acceleration. The U.S. light tight oil rig count had increased to about 600 at the end of the second quarter, a level we think would result in production far exceeding the likely call on U.S. shale next year. Critically, that growth is plausible with no further increases in the rig count; it instead reflects dramatic shifts in producer efficiency and productivity.

The substantial increase in production that we project in a flat rig scenario is enough to cause renewed turmoil in oil markets in 2018, especially if it coincides with the waning or outright cancelation of OPEC curtailments as we expect. It is not yet clear whether the industry has recognized the dangerous trajectory it is following. So far, most producer commentary suggests that it hasn’t, and there are few signs that rig additions are already slowing. Most of the upstream firms we cover still expect strong growth this year and/or in 2018.

If we’re right and production does ramp too rapidly, the shale industry can’t quickly halt new drilling. Many rigs are contracted for fixed periods, with penalties for early termination. These contracts will roll off gradually, preventing producers from quickly dropping rigs if it becomes clear that U.S. shale is overheating. Conventional wisdom is that shale oil supply is much more responsive than the megaprojects of years past, and that’s true, but only to a point. There is still a three- to six-month lag between significant commodity price reversals and the resulting dial-down or ramp-up of activity levels.

To make matters worse, there is an additional delay before the impact of adding or removing rigs is reflected in production levels. Drilling and completion is a lengthy process, with little incentive to halt once it has begun. And batch completions are becoming more common as the use of multiwell pads increases, making supply additions lumpier. Consequently, last year’s decline in shale output was not arrested until roughly six months after the horizontal rig count nadir in May. This delay mirrors the earlier lag between the initial drop in active horizontal rigs at the start of the downturn and the stalling, three to four months later, of crude production growth in the Lower 48.

Combined, these delays exacerbate the potential oversupply situation because (1) the full brunt of the most recent rig count increases has yet to be realized, and (2) if producers do decide to scale back operations, it will take several months to achieve a production response, with additional unwanted growth in the interim. The bottom line is that the market may be underestimating the medium-term supply ramifications of today’s activity level.

In a Difficult Macro Environment, Seek Low Costs and Low Leverage
Not surprisingly, upstream stocks are highly correlated with commodities. We’ve outlined headwinds for the industry in 2018, with the expiration of OPEC production cuts combined with strong output growth from U.S. shale producers creating a supply-rich environment next year and keeping a lid on crude prices. We would not be surprised if prices dip below our full-year WTI forecast of $45/bbl for a period. Our long-term forecast is relatively bearish too. Our valuations are based on a midcycle forecast of $55/bbl for WTI, which is lower than many sell-side estimates (we believe efficiency and productivity gains will keep a lid on costs even after factoring in cyclical reinflation). Investors holding, or considering holding, E&P stocks should take our bearish stance into account.

Paradoxically, we still see some attractive opportunities in the segment. We think the market is also failing to appreciate the potential for further cost reductions through technical innovations and efficiency gains. That means equity prices are baking in unnecessarily lofty unit costs as well as optimistic crude prices, and to an extent, the two offset each other. In fact, some of the highest-quality E&P companies--the ones at the very low end of the cost curve--look undervalued. These stocks are not immune to the challenging crude environment we envision, but their low financial leverage positions them better than peers to cope with weakening prices. And in the long run, their best-in-class cost structures will enable them to outperform.

RSP Permian is currently trading more than 35% below our fair value estimate. It operates exclusively in the Permian Basin, which offers very attractive drilling economics and is expected to be a major growth center for U.S. shale over the next several years. The company’s acreage contains almost 6,000 horizontal drilling locations, supporting several decades of activity at the current run rate. Almost all of it is located in core areas in the Midland and Delaware basins--there’s no “filler” acreage in less lucrative peripheries.

Though the entire industry is focusing on cutting costs and enhancing efficiency, RSP is well ahead of the curve. In 2016, it reported finding and development costs of $6 per barrel of oil equivalent and operating expenses of $11/boe. Of its production that year, 73% was crude oil, which the company was able to sell at a discount of just 5% to the WTI benchmark (because of its proximity to local infrastructure). That translates to a WTI break-even of less than $25/bbl, which is well below the peer average and positions the company well to cope with difficult commodity price environment we’ve outlined here.

Management forecasts 90% production growth in 2017, coming off a low base, and the company is on track to hit that goal. Preliminary guidance for 2018-19 suggests annual growth of about 30% in both years, with two additional rigs added each year. Adding rigs seems unlikely in the crude environment we forecast, but factoring in reasonable productivity improvements, we think the company can come close to this target with the rigs it is already running (we forecast 25% growth in 2018).

 Diamondback Energy and  Oasis Petroleum also screen well on leverage and recycle ratios. The former has a lot in common with RSP Permian--both started out in the Midland Basin, and last year both augmented their asset portfolios with Delaware Basin acquisitions. Of the two, Diamondback has slightly more leverage, although both have excellent balance sheets. Diamondback is also the larger company, with more acreage and higher volumes (though it isn’t growing quite as quickly as RSP, since it had a larger base going into 2017). Our net asset value analysis suggests that RSP Permian is the more undervalued stock, but both look attractive for long-term investors.

Oasis Petroleum operates in the Bakken Shale, also a major growth engine, but also a more mature play with less scope for further productivity gains. Like both Permian companies, it has excellent economics and very strong operating margins. However, it lacks the balance sheet strength of these other picks. Its net debt/capital ratio of 44% is about average for the peer group, but if net debt/EBITDA is used to measure leverage instead, Oasis screens very poorly. Therefore, next year could be very challenging for this company if our oil price forecast is correct. However, Oasis would be more likely to outperform in a bullish commodity environment.

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Dave Meats, CFA does not own shares in any of the securities mentioned above. Find out about Morningstar's editorial policies.
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