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  • Roger S. Conrad

Thoughts on US Onshore Oil Production

By Peter Staas on Feb. 5, 2016

Any improvement in oil prices hinges on a decline in overall production, a chunk of which will come from shale plays in the US onshore market.

The US oil-directed rig count has plummeted to 498 active drilling units from its October 2014 high of 1,609—an almost 70 percent drop. All signs point to this downtrend continuing in the near term, as rig contracts roll off and the inventory of drilled but uncompleted wells grows.

(Click graph to enlarge.)US OIl Rigs

With upstream operators focusing on their core acreage and using enhanced completion techniques (longer laterals, reduced spacing between fracturing stages and larger loads of silica sand) to pull production forward, US oil output has proved remarkably resilient since prices began to fall in mid-2014.

Nevertheless, the decline curve is the one constant in the ever-changing oil and gas industry; in the back half of last year, reduced drilling activity and the natural retreat in output from existing wells started to assert themselves.

Data from the Energy Information Administration indicates that the growth rate in US onshore oil production declined by almost half last year, with output through the end of November up 9.48 percent from the prior year.

(Click graph to enlarge.)US Annual Onshore Oil Production and YoY Change

In May 2015, US onshore oil production from the Lower 48 began to decline on a sequential basis, while the year-over-year growth rate slowed significantly as the year wore on.

(Click graph to enlarge.)YoY and QoQ Change in Monthly US Onshore Oil Production -- Lower 48

Production trends in states with significant output from shale oil plays—Colorado, North Dakota, Oklahoma and Texas—tell a similar story.

(Click graph to enlarge.)YoY and QoQ Change in Monthly US Onshore Oil Production By Shale Play

All signs point toward US onshore oil output rolling over in 2016, fueled by lower commodity prices, capital constraints and expiring hedges in the upstream segment. .

Commentary and guidance from the handful of prominent US exploration and production companies to provide business updates in recent weeks reflect these challenges.

For example, Continental Resources (NYSE: CLR)—a leading producer in the Bakken Shale and the promising South-Central Oklahoma Oil Province (SCOOP)—on Jan. 26 announced a capital budget of $960 million for 2016. This level of spending represents a 66 percent reduction from 2015.

About 35 percent of this capital will go toward activities in North Dakota’s Bakken Shale, while 28 percent will go to the SCOOP and 15 percent will support development efforts in the STACK, which stands for Sooner Trend, Anadarko (Basin), Canadian and Kingfisher Counties.

Management also called for production to slip to between 180,000 and 190,000 barrels of oil equivalent per day in the fourth quarter of 2016, compared with a projected 210,000 to 220,000 barrels of oil equivalent per day in the first three months of the year.

Meanwhile, Hess Corp (NYSE: HES), a prominent player in the Bakken Shale that also owns a sizable portfolio of international assets, announced a capital budget that was 40 percent lower than during the previous year—and 20 percent less than the amount contemplated when the company issued guidance in October 2015.

This spending plan will fund two drilling rigs in the Bakken Shale, a program that will support annual production of 95,000 to 105,000 barrels of oil equivalent per day this year. In 2015, Hess Corp’s operations in North Dakota flowed an average of 112,000 barrels of oil equivalent per day.

During a conference call to discuss Hess Corp’s fourth-quarter results, management outlined the rationale for these declines with a sentiment that we expect to hear throughout this earnings season: “Our focus is on value, not volume, and we do not think it makes sense to accelerate production in the current environment, particularly given the recent further deterioration in the oil markets.”

Noble Energy (NYSE: NBL), which operates in the Niobrara Shale and acquired a footprint in the Eagle Ford Shale and Permian Basin from its all-stock purchase of Rosetta Resources, recently called for its overall hydrocarbon production to remain flat in 2016, despite slashing its capital budget by 50 percent from 2015.

Expect more exploration and production companies to announce plans to reduce capital expenditures, as they seek to align spending with cash flow. This strategy will result in flat to declining output for many oil producers. The names at the most risk include smaller producers or those with marginal acreage and/or tenuous financial positions.

The Energy Information Administration’s most recent Short-Term Energy Outlook estimates that US oil production will decline to about 8.5 million barrels per day in December 2016, down from the 9.2 million barrels per day averaged in the final month of 2015.

Whereas the start-up of new projects in the Gulf of Mexico will boost offshore production over the next two years, the Energy Information Administration estimates that onshore output will tumble to less than 6.2 million barrels per day in September 2017, down 1.4 million barrels per day from the high reached in the second quarter of 2015.

Although all the shale plays likely will suffer a diminution of output over the next 12 to 18 months, the magnitude of these declines will vary. However, in all cases, core acreage—areas with existing infrastructure and the best economics—will prove more resilient than the fringe. Investors must also remember that even the best basins contain marginal acreage and producers.

Recent well results in Oklahoma’s SCOOP and STACK, for example, suggest that oil production from these plays could hold up reasonably well and potentially even grow.

Leveraged exposure to this resource base, coupled with a strong balance sheet, explains why Newfield Explorations (NYSE: NFX) shares rallied 20 percent in 2015—one of the few exploration and production stocks to finish the year with a gain.

Perpetual latecomer Devon Energy Corp (NYSE: DVN), which has sought leverage its strong balance sheet to diversify its onshore exposure away from its legacy assets in the Barnett Shale and other challenged areas, also recently acquired 80,000 acres in the STACK play for $1.9 billion from privately held Felix Energy—a premium price.

The Permian Basin in West Texas has also emerged as an area of relative strength, though the falling rig count and potential shut-ins of legacy stripper wells could lead to moderate production declines.

Producers in the Permian Basin benefit from several advantages, including lower production costs relative to other shale plays and the option to deliver output to Cushing, Oklahoma, or hubs on the Gulf Coast. The region also includes the potential to tap stacked plays, meaning that producers can extract hydrocarbons from multiple horizons at a single well site.

In these challenging times, investors have latched onto this bright spot, resulting in premium valuations for the best exploration and production companies that offer leveraged exposure to this growth story.

Accordingly, select operators in the Permian Basin have been able to issue equity at will to fund acquisitions and field development without taking on significant leverage—a huge advantage in an environment where oil and gas prices remain lower for longer.

US Upstream Equity Issuance

Equity issuance by US independent oil and gas producers has tapered off significantly since the heyday of the shale oil and gas revolution, but operators in the Permian Basin have continued to raise capital in this manner without being penalized by the market.

In fact, the seven Permian players that have issued equity over this period have delivered an average total return of almost 6.4 percent since announcing these deals, demonstrating investors’ appetite for this growth story.

Ready access to low-cost capital for some of the best-positioned producers in the Permian Basin, combined with Chevron Corp (NYSE: CVX) and other well-capitalized oil companies’ sizable legacy positions in this area, suggest that this part of West Texas should fare reasonably well even if oil prices remain lower for longer.

The Bakken Shale, on the other hand, faces headwinds because of its relative distance from major demand centers on the Gulf Coast and the expense associated with shipping crude oil by rail to refineries on the West Coast and the East Cost.

Meanwhile, the Eagle Ford Shale in South Texas produces significant volumes of condensate and natural gas liquids (NGL) for a domestic market that faces a significant supply overhang and an export market that has limited capacity to absorb additional volumes. The restart of condensate exports from Iran presents a particular challenge to US aspirations of winning market share in Asia.

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