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Gas-Directed Drilling Activity Provides Insight into US Producers’ Response to Lower Oil Prices

By Peter Staas on Jan. 1, 2015
Natgas by Play Small

The combination of slowing oil demand growth in China and other key markets and surging output from US shale plays—and its implications for global spare productive capacity—has sent crude prices plummeting.

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.)

Investors looking for historical antecedents to predict how the North American energy complex will respond to lower crude-oil prices should look to developments in the domestic natural-gas scene.

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

Digging into natural-gas production data reveals several trends that should also inform developments in North American oil markets.

The seven major unconventional plays that the Energy Information Administration tracks in its Drilling Productivity Report—the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian and Utica—in August 2014 accounted for a whopping 48.6 percent of US natural-gas output. 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.

(Click graph to enlarge.)NatGas Production -- Major Plays vs Rest of US

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 its superior economics, output from the Marcellus surged by 620 percent to 4.2 trillion cubic feet between 2009 and 2013. This momentum has continued into 2014, with natural-gas production climbing another 34 percent from year-ago levels over the nine months ended Sept. 30. 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 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. (See Breaking Down the US Onshore Rig Count.)

Implications for Oil Producers

Expect oil producers to follow a similar game plan and shift rigs from marginal basins such as the Mississippi Lime and emerging plays such as the South-Central Oklahoma Oil Province (SCOOP) to core acreage that offers the best internal rates of return.

Some will lay down vertical rigs, as drilling horizontally offers higher initial production rates. 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.

We’ve already seen some early signs of movement on these fronts. According to oil-field services outfit Baker Hughes (NYSE: BHI), the number of active rigs that drill vertical wellbores has plummeted from 384 units at the end of the second quarter to a record low of 309 in the week ended Dec. 26, 2014.

(Click graph to enlarge.)US Onshore Rig Count -- Vertical vs Horizontal

Last week’s rig count numbers also brought a significant drop in the number of rigs operating in California, which fell to 28 units from 45 in the previous week.

These shifts won’t necessarily reduce production volumes overnight, as oil and gas companies will look to offset the effect of lower prices by growing volumes. Some hedging on the part of producers will also support drilling activity while oil prices are below break-even costs.

US oil prices would need to overshoot the levels supported by prevailing supply and demand conditions to prompt producers to idle rigs and reduce capital expenditures dramatically. Weak balance sheets and higher-cost asset bases will compel some operators to scale back.

This supply response in the US and elsewhere will signal that we’re near the bottom of the commodity cycle. The question isn’t whether this will happen, but rather how long the process will take to occur.

Any moderation in production volumes associated with anticipated reductions in capital expenditures won’t show up for several quarters, especially with operators focusing development activity in their core acreage and pushing for 15 percent to 20 percent price breaks from service providers.

And with US producers able to sink high-probability new wells within a week, this shadow capacity should keep a lid on oil prices in the intermediate term, assuming OPEC maintains its output levels and no major disruptions occur in the usual hot spots.

Investment Ramifications

With the exception of a handful of high-quality operators, investors should remain underweight upstream names, especially those with higher production costs, heavy debt loads and marginal acreage.

Now isn’t the time to be a hero and try to catch a falling knife; wait until they’ve clattered to the floor and pick up high-quality namesthat can still cut it–we like EOG Resources (NYSE: EOG) and Occidental Petroleum Corp (NYSE: OXY) .

However, this sterling buying opportunity remains at least two quarters away. The next few months should bring some bounces in crude oil and energy stocks that will suck in the unwary—view rebounds these as a chance to exit weaker names.

Investors should also be wary of gathering-and-processing names with an asset base that’s concentrated in marginal basins or contracts that entail significant exposure to the price of natural gas liquids (NGL).

Although these master limited partnerships don’t necessarily run the risk of cutting their distributions, lower expectations for growth could cause these stocks to underperform.

On the long side, focus on best-in-class midstream operators with exposure to the best-positioned basins.

As we explain in Making Sense of the Marcellus Shale’s Midstream Madness, Williams Partners LP (NYSE: WPZ) and other names that own takeaway capacity from Appalachia have ample opportunity for organic growth–a stark contrast to Crestwood Midstream Partners LP (NYSE: CMLP), which continues to be hamstrung by declining throughput volumes on its legacy assets in the Barnett Shale and Fayetteville Shale.

Expect similar dynamics to play out in the oil market as competition between basins intensifies and drilling activity in some areas feels the squeeze.

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