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  • Roger S. Conrad

The Next Phase of the Shale Revolution

By Peter Staas on Apr. 25, 2015

What are the intellectual underpinnings of the gut call investors make when they buy shares of US oil and gas producers and other beaten-down names in the energy patch?

For many, this trade represents a bet that crude-oil prices have bottomed and will recover, a call that reflects the huge drop in the US onshore rig count (down 45 percent since June 30, 2014) and the expectation that output growth will slow to a rate that supports higher prices.

(Click graph to enlarge.)BHI Rig Count

Bulls argue that prevailing oil prices won’t encourage the investment and output growth needed to offset the global decline curve (about 2.5 percent annually)—an observation that applies to both US shale plays and international development activity.

Meanwhile, the relatively steep decline rates of shale oil and gas wells relative to conventional fields also mean that the market could rebalance faster than in previous cycles, potentially resulting in a V-shaped recovery.

Oil-field services outfit Core Laboratories (NYSE: CLB), for example, recently asserted in its first-quarter earnings release that US oil production will be flat to down slightly in 2015. This projection reflects reduced drilling and completion activity and applying a 70 percent decline rate to unconventional wells drilled in 2014, a 40 percent decline rate to the 2013 vintage and a 20 percent decline rate to those from 2012.

The Energy Information Administration’s (EIA) most recent Drilling Productivity Report estimates that oil output from the Bakken Shale, Eagle Ford Shale and Niobrara Shale will decline slightly on a sequential basis in May 2015. However, oil production in these plays would still be up significantly relative to the previous year.

(Click graph to enlarge.)DPR Data QoQ and YoY Growth

On the other side of the equation, the International Energy Agency recently upped its estimate for 2015 consumption growth by about 1.1 million barrels per day, citing a recovery in the US and some European countries as well as growing demand in China, India and other emerging markets.

Nevertheless, we remain skeptical of the recent rally in crude-oil prices and commodity-sensitive energy equities.

For one, the recent upswing in WTI prices coincides with the seasonal upturn in refinery run rates.

US refiners usually shut down a proportion of their capacity for maintenance and upgrades in the fall and winter months, tempering demand for crude oil. However, these turnarounds wind down in the spring, when operators gear up to run all out during the summer driving season, a period of peak demand represented by the circles on our graph.

(Click graph to enlarge.)US Refinery Outages -- Historical and Planned

Check out this graph comparing US refineries’ average daily consumption of crude oil over the past five years to the run rate thus far in 2015.

(Click graph to enlarge.)US Refineries -- Weekly Oil Consumption

US downstream operators idled an average of 1.5 million barrels per day of refining capacity during the first two months of the past five years; the refinery complex then runs at reduced capacity for the first 11 weeks to 12 weeks of the year.

Starting in the second quarter, refining throughput gradually increases through week 28 (roughly midyear). Based on the five-year averages, the pick-up in demand from the first quarter’s seasonal lows to the midyear highs hovers around 2 million barrels per day.

Bullish commentators often argue that US inventory builds should begin to moderate this month, as refineries ramp up their activity. However, this argument ignores the facts on the ground: Refinery margins have widened markedly since January, prompting operators to run their plants at elevated utilization rates in the first quarter.

With US refineries already running at 89 percent of their nameplate capacity, the industry has limited scope to boost throughput rates over the next few months. In other words, the uptick in oil consumption will fall short of the 2 million barrels per day averaged over the previous five years.

Investors betting on this seasonal bump to help alleviate elevated inventories likely will be disappointed; the volume of oil in storage has continued to grow at a faster-than-expected pace despite refineries running at higher utilization rates.

As of April 22, 2015, US crude-oil inventories had swelled to levels that exceeded the four-year average by 30 percent. Meanwhile, the onset of another refinery turnaround season will lead to additional stockpiling in fall and winter, exerting further pressure on US oil prices—a seasonal trend that becomes more pronounced at higher production levels.

(Click graph to enlarge.)US Oil Inventories

In the near term, several factors could also push back the recovery in WTI—whatever shape that rebound ultimately takes—and keep oil prices lower for longer.

For one, many producers have focused their development activity on their core acreage—the rocks that generate the best internal rates of return—in an effort to bolster cash flow, another trend that could lead to a near-term production bump and help to continue the momentum from the prior year.

The precipitous drop in oil prices and the rig count, coupled with producers postponing well completions until conditions improve, has led to overcapacity in many onshore oil-field service categories, enabling customers to push for prices breaks.

Most producers have cited price cuts of 10 percent to 30 percent as a factor that will help to boost returns and lower break-even costs.

For example, oil-field services firms have highlighted their efforts to lower the cost of the crush-resistant silica sand used in hydraulic fracturing—one of the reasons that we’ve had Sell ratings on Emerge Energy Services LP (NYSE: EMES), Hi-Crush Partners LP (NYSE: HCLP) and US Silica (NYSE: SLCA) since fall 2014. (See Sand in the Gears: Elevated Downside Risk for High-Flying Proppant Producers.)

Hi-Crush Partners’ recent decision to maintain rather than raise its quarterly distribution underscores the challenges facing this business.

Besides price breaks from oil-field service providers eager to keep capacity working, ongoing efficiency gains and technological improvements should continue to lower break-even costs and generate higher recovery rates per well.

In particular, the Permian Basin, a mature oil play in West Texas that’s been revivified by horizontal drilling and hydraulic fracturing, appears ripe for efficiency-driven production gains as operators in this basin shift into manufacturing mode and ramp up pad drilling. (See Salute Your Drillmasters: Efficiency Gains Lower Production Costs.)

By the same token, a V-shaped recovery could also be forestalled or moderated by a near-term rally in crude-oil prices that gives highly leveraged operators and those with marginal acreage an opportunity to hedge future production.

Another factor that could come into play: The shadow inventory of wells that producers have drilled but left uncompleted in the major shale oil plays hovers around 4,000. When you include the Utica Shale and the Marcellus shale, this backlog exceeds 4,700.

(Click graph to enlarge.)DUC Wells

Although the number of drilled but uncompleted wells represents a fraction of the roughly 43,000 wells sunk last year, this pent-up supply waiting to be tapped when oil prices recover could moderate whatever rebound occurs—depending on the pace at which producers fracture these wells.

According to research from Bloomberg Industries, larger players such as ConocoPhillips (NYSE: COP), EOG Resources (NYSE: EOG), Exxon Mobil Corp (NYSE: XOM), Hess Corp (NYSE: HES) and Occidental Petroleum Corp (NYSE: OXY) account for a sizable chunk of these wells. Many of these drilled but uncompleted wells also occur in fringe areas, where returns would benefit from higher oil prices or lower completion costs.

Investors should expect this shadow inventory to continue to grow, as well-heeled producers look to avoid rig termination contracts and eventually earn higher future returns.

Chatter about re-fracturing older wells has also picked up. This practice offers decent economics in the current environment by cutting out drilling costs and the need to construct new takeaway infrastructure.

Schlumberger’s (NYSE: SLB) management team addressed this phenomenon during the oil-field service giant’s first-quarter earnings call:

So in terms of how many wells, I would say there are thousands of wells in North America land that are candidates for re-fracturing, and this is both shale liquids and shale gas. In terms of the market potential, I think you’re talking billions in terms of revenue opportunities over an extended period of time, but this is quite a significant market opportunity.

And I think the key here is that we are so confident in our ability to identify the right candidates and execute the re-fracturing work that we are prepared to take significant risk in terms of how we go about doing this work. We are in many cases, if we can select the candidates, prepared to foot the entire bill for the re-fracturing work and then get paid back in production.

We’ve heard about re-fracturing wells in the past from Core Laboratories and Comstock Resources (NYSE: CRK), a marginal producer that opted to put some of its legacy wells in the Haynesville Shale through this process.

Schlumberger’s offer to foot the bill on re-fracturing work and take a cut of the production suggests a high level of confidence in its technology and execution—when the oil-field services giant selects the wells.

We’ll have to see whether re-fracturing and this new contract structure gain traction among producers. Schlumberger inked a similar joint venture with ailing Forest Oil Corp to showcase the effectiveness of its HiWay fracturing technologies. This approach to contracting didn’t catch on at the time, but shrinking cash flow in the US upstream segment could bolster the appeal.

Lower for Longer

Debating when and where crude-oil prices will bottom is a stimulating exercise, and the outcome has important implications for earnings, investor sentiment and stock returns in the energy sector.

At the same time, the number of moving parts involved in forecasting near-term movements in oil prices is considerable and can involve unpredictable geopolitical elements. A more meaningful question might be what will the North American energy landscape look like in coming years?

First and foremost, the upsurge in North American oil production, led by US unconventional plays, has helped to align global supply with annual demand growth in China and other emerging markets.

Despite Brent crude oil averaging more than $100 per barrel and WTI averaging almost $95 per barrel for four years, the oil and gas industry’s huge investments in mega-projects have resulted in negligible production growth in non-OPEC countries outside of North America.

(Click graph to enlarge.)Oil Production Trends

In short, without US shale oil and gas output, global energy prices likely would be a lot higher; unless international oil companies dramatically improve their project execution, these unconventional plays will remain critical to maintaining a healthy supply-demand balance in light of growing demand in emerging markets and the base decline rate from producing fields.

The relatively steep decline rates associated with wells in shale plays, predictable success rates (dry holes are rare) and increasingly short development times make these unconventional plays an ideal source of swing production.

We would expect the price of WTI ultimately to settle in a range that promotes some shale oil and gas development without incentivizing unrestrained production from plays with marginal economics.

This settling process won’t happen overnight and likely will entail a fair amount of volatility. Given the upstream industry’s huge cuts in capital expenditures and drilling activity, a sharp rebound in oil prices could occur—followed by a flood of production and another retrenchment in prices.

And with US producers able to sink high-probability wells within a week, this shadow capacity should keep a lid on oil prices once the commodity settles into its trading range.

Such a situation has historical antecedents. North America boasts a number of prolific natural-gas plays in which producers could accelerate drilling activity if prices were to climb to between $4.50 and $5 per million British thermal units.

Based on total reserves, Louisiana’s Haynesville Shale is one of the largest gas plays in the US. However, this play has fallen out of favor because it produces negligible volumes of crude oil and natural gas liquids, higher-priced hydrocarbons that help to boost economics.

This unfavorable production mix explains why drilling activity in the Haynesville Shale slumped sharply after 2008 and gas production from this field had plummeted by almost one-third from its peak.

However, the Haynesville Shale’s rig count and production levels appear to have bottomed last winter, suggesting that natural gas prices over $4.50 per million British thermal units would incentivize producers to accelerate drilling activity in the play’s core region.

Most analysts estimate that natural-gas prices of $5 per million British thermal units would enable producers to make money in the marginal portions of the Haynesville Shale.

The region already boasts sufficient pipeline and processing capacity to handle an increase in production, while its proximity to proposed export capacity on the Gulf Coast is another plus.

In short, any sustained upsurge in North American natural-gas prices would be stymied by an influx of output from the Haynesville Shale and other plays. We expect a similar situation to play out in the US oil market, with producers ready and willing to ramp up output from second- and third-tier acreage.

External Discipline: Downside Risks from the Outside

Several external factors will also shape the US energy landscape in coming years.

Saudi Arabia may have ceded the mantle of global swing producer, but the kingdom and OPEC appear unlikely to relent in the battle for global market share and will do anything to prolong the golden age of oil demand.

As Schlumberger’s management team observed during the firm’s first-quarter earnings call, the Middle East’s big producers continue to ramp up investment in an effort to squeeze out higher-cost competition.

Saudi Arabia’s commitment to retaining market share instead of slashing output to support oil prices reflects the hard lessons learned during the early 1980s, when growing non-OPEC production pressured oil prices.

Back then, Saudi Arabia and OPEC reduced their output to address the supply overhang and bolster prices—a move that merely encouraged further production growth from outside the cartel. By 1985, the cartel’s share of the global oil market had shrunk to 26 percent from a high of 53 percent in 1972.

Saudi Arabia in December 1985 announced plans to boost output in an effort to recapture the market share lost to non-OPEC producers and grew its crude volumes by almost 1.7 million barrels per day over the next 12 months.

And over the ensuing half-decade, OPEC expanded its annual production to almost 24 million barrels per day from less than 15 million barrels per day in 1985. (See The Oil Down-Cycle: Lessons from the Past.)

Ignore commentators who claim that Saudi Arabia has achieved its goal of curtailing the growth of non-OPEC supply and could opt to cut exports in June. Crude oil remains Saudi Arabia’s bread and butter; winning market share and prolonging the age of oil and gas remain a high priority, especially with the international community potentially dropping sanctions against Iran.

The debt and capital markets will also condition US upstream operators’ behavior and decision-making in the coming years.

Extracting oil and gas is a capital-intensive endeavor. An extended period of elevated oil prices helped to fuel the shale revolution, but ready access to low-cost capital also played a critical role.

The majority of shale producers have run deficits in recent years, investing more in their operations than they generated in cash flow. These shortfalls forced them to borrow to fund the difference.

(Click graph to enlarge.)US Upstream Cash Flow Shortage

According to a recent report from the Bank of International Settlements, the oil and gas industry’s total debt has ballooned to $2.5 trillion—about 2.5 times where it stood at the end of 2006.

Over this period, oil and gas companies’ bonds outstanding climbed at an average annual rate of 15 percent, while syndicated loans to this group increased by about 13 percent per annum. US companies account for about 40 percent of the total bonds and syndicated loans outstanding in this category.

The Bank of International Settlements estimates that the average debt-to-assets ratio for smaller US oil and gas producers has almost doubled over the past eight years, while this metric has remained flat for large energy companies.

This heavy reliance on borrowing to fund drilling and development activities in US shale oil and gas plays will condition how these companies respond to lower oil prices, a development that threatens to reduce cash flows correspondingly.

To meet their payment obligations and comply with their loan covenants, many US oil and gas producers have sought to bolster their cash flow by growing their hydrocarbon output while aggressively reducing capital expenditures.

Our graph tracking US independent oil and gas producers’ planned spending cuts and the Bloomberg consensus estimate for 2015 output growth tells the tale.

(Click graph to enlarge.)CAPEX vs Production Growth

Note that many of the production declines in this graph reflect the effect of asset divestments—another strategy to shore up balance sheets and fund drilling activity—not an actual reduction in output.

Thus far in 2015, US upstream operators have raised significant capital in an effort to plug their widening cash flow shortfalls and to offset reductions to their credit facilities when their lenders reevaluate their borrowing bases in spring and fall.

(Click graph to enlarge.)
US Upstream Equity Issuance 2015

All told, these exploration and production companies have issued or have filed to sell $10.431 billion worth of common shares and $18.975 billion in bonds—almost $30 billion in capital.

(Click graph to enlarge.)
US Upstream Bond Issuance

As long as the public and private markets remain open, expect more US upstream operators to issue equity and bonds.

More Lessons from the Gas Market

Our history lesson starts with the golden age of US natural gas, a period when shrinking domestic supply elevated the price of this commodity, incentivizing the development of higher-cost production and the commercialization of the Barnett Shale and the Fayetteville Shale—the forebears to Appalachia’s mighty Marcellus Shale.

But these salad years eventually wilted. Surging hydrocarbon production from prolific US shale plays overwhelmed domestic demand for natural gas, depressing the price of this commodity to less than $3 per million British thermal units (mmBtu) from a peak of more than $13 per mmBtu in summer 2007.

(Click graph to enlarge.)Monthly US Natgas Production vs Price -- 10-Yr History

Producers responded to the pain by shifting their drilling activity to plays that offered the best returns.

The seven major unconventional plays that the EIA tracks in its Drilling Productivity Report accounted for a whopping 48.6 percent of US natural-gas output in August 2014. Three years earlier, this figure stood at about 30 percent.

(Click graph to enlarge.)Major Shale Plays as Percent of US Natgas production

This trend reflects surging output growth that has outpaced steadily declining production outside these seven major plays.

At an even higher level of granularity, we can see that production has surged in the plays that offer the best economics and declined in those that generate inferior returns in the current pricing environment.

(Click graph to enlarge.)Annual NatGas Production Seven Major Shale Plays

Consider the contrasting fortunes of Appalachia’s Marcellus Shale and Louisiana’s Haynesville Shale.

Thanks to superior economics, output from the Marcellus surged by 620 percent to 4.2 trillion cubic feet between 2009 and 2013. This momentum continued into 2014, with natural-gas production climbing another 31percent. In fact, the Marcellus Shale accounts for about 20 percent of US natural-gas production. (See Takeaways from the Marcellus Shale’s Growing Pains.)

Although Louisiana’s Haynesville Shale contains significant natural-gas reserves, unfavorable economics have prompted producers to curtail drilling activity in the region. Accordingly, output from this basin tumbled by 21.7 percent in 2013 and 13.1 percent last year.

And over the past several years, the number of active rigs in gas-focused plays with less appealing economics—the Barnett Shale, the Fayetteville Shale and the Haynesville Shale—has declined dramatically.

Instead, producers ramped up activity in areas that produced significant volumes of crude oil and natural gas liquids, higher-priced hydrocarbons that generated superior returns. (See Breaking Down the US Onshore Rig Count.)

Expect a similar story to play out in the oil patch, except this time distressed producers won’t have the option of improving returns by shifting their focus to liquids-rich plays.

Instead, upstream operators likely will relocate rigs from marginal basins such as the Mississippi Lime to core acreage that offers the best internal rates of return.

Companies will lay down vertical rigs, as drilling horizontally offers higher initial production rates and better returns. Breitburn Energy Partners LP (NSDQ: BBEP), for example, opted to drop all of its vertical rigs operating in the Permian Basin in favor of running a single horizontal rig.

Areas that face higher transportation costs to deliver their volumes to market—the Bakken Shale and Canada’s tight oil plays spring to mind—will also be relatively disadvantaged in this environment.

Acreage quality also varies widely within the best plays, one of the reasons that the inventory of drilled but uncompleted wells in the Eagle Ford Shale has been concentrated in certain counties. In touting its own acreage position, EOG Resources has indicated that some fringe areas in the Bakken Shale struggle to generate a decent return with oil prices hovering around $95 per barrel.

In other words, investors shouldn’t blindly buy the basin—pay attention to acreage quality, the number of potential drilling locations and the company’s execution.

In this environment, producers with marginal assets and/or excessive amounts of leverage will feel the squeeze, ceding market share to output from first-tier acreage and companies with sound balance sheets. Some of these names—especially those with quality assets but distressed balance sheets—will ultimately be absorbed by larger companies. Others will end up in bankruptcy.

How to Play It

Investors should expect volatility in energy equities and oil prices, thanks to a flood of tourists looking for value and a US production landscape that’s highly fragmented and, frankly, overpopulated. On the equity side, the tourists eventually will get bored and go home; on the production side, weak hands eventually get crowded out.

Accordingly, the recent rally in shares of US oil and gas producers gives investors an excellent opportunity to exit any weaker names.

We prefer to stand aside on most upstream names, as valuations look full in an environment where crude-oil prices likely will remain lower for longer now that service costs have started to go down, drilling efficiency continues to improve and Saudi Arabia remains committed to building market share by ramping up exports.

Investors interested in wading into the upstream space should consider easing into their positions and focusing on names with strong balance sheets, low production costs, a history of solid execution, and franchise assets that can deliver production growth in a challenging environment. Names that can expand their output and win market share should outperform, while their cash-strapped peers or those with inferior assets will struggle.

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