The oil and gas industry had barely finished congratulating itself on surging U.S. crude oil production, when worries surfaced about the effect on commodity prices. In a recent Baird Energy report, analysts said the CEO of Plains All American Pipeline LP (NYSE: PAA), Greg Armstrong, “waved the red flag regarding oil prices” in the company’s recent quarterly conference calls.

“Few, if any, energy sector participants have a better picture of the North American crude oil market than PAA management,” they said, adding that a correction in U.S. crude oil prices is “an event against which PAA would be insulated fundamentally by a fee-oriented business model, but which producers and price-exposed midstream participants would not.”

“Widening differentials would suggest a selective long refiner/short producer trade strategy in our view. On balance, lower oil prices would be a negative headwind for the entire energy sector, including MLPs, due to stronger trading correlations to crude oil than other equities,” he added.

Many observers are calling for crude oil exports to be allowed, believing approval would prop up prices, despite production hikes. (For more on this, see the sidebar in this issue’s cover story).

In an early February report, RBC Capital Markets put forth its five-year outlook for U.S. oil production growth and more. Its analysts examined production potential for key oil-producing basins, as well as breakevens that could determine how producers react if prices do, in fact, decline.

In the Permian, they look for crude output to roughly double to 2.5 million barrels of oil per day over the next five years, propelled by the vertical-to-horizontal shift. The horizontal Permian will add about 200,000 barrels of oil per day to U.S. crude production in 2014, and about 225,000 to 275,000 barrels per day for each year from 2015 to 2018. “Due to the relative infancy of horizontal drilling in the Permian, we see meaningful inventory remaining in the basin well past 2020, but these locations could get slightly gassier over time,” they say.

As for Permian take-away, it is proliferating. RBC estimates that more than 800,000 barrels per day of incremental crude oil pipeline capacity will be added by 2015 — with about half in service this year and half in 2015.

Permian rig efficiencies have room to run, they say, and will contribute to a 37% decline in days to drill per well, to 24 days from 38 currently. “This implies that wells per rig will increase by about 50%, to 15 wells per rig in 2020 from 10 wells per rig currently.”

In the pressure-pumping business, the Permian hosts some 15% of the hydraulic horsepower for fracing. “Average price per stage has declined by 21% in the past year, and the average number of frac stages per well has increased by about 8%,” the analysts say.

What are Permian economics in relation to crude pricing? The breakeven numbers, at 10% field-level internal rate of return (IRR), vary greatly, the analysts say. “We think certain plays in the best parts of the basin are economic at as low as $45 per barrel, while fringier areas or less production intervals might take prices closer to $80 per barrel to work.”

The average for the basin is about $65. Permian horizontal activity will accelerate at $90 or above per barrel, but new activity might flatten or decline at $80, they say. “We think oil prices below $70 per barrel would cause most all horizontal Permian activity to come to a halt.”

Next to the Permian, the Gulf of Mexico wields the most oil-producing might. It has been declining, and is currently producing 1.2 million barrels per day. But large projects (50,000-plus barrels per day) coming online in 2014 to 2015 should help post an additional 165,000 barrels of oil per day beginning in 2015.

“There have been several large (100-plus-million-barrel) post-Macondo deepwater discoveries, including Coronado, North Platte, Raptor and Shenandoah,” they say.

Gulf breakeven economics depend on prospect sizes, water depth and distance to shore. RBC thinks economics can hold at as low as $40 per barrel; however, there are high upfront capital costs, long lead times to production and cost overruns to consider. “As a result, E&Ps will typically assume an oil price much lower than the current spot price/futures prices when making an investment decision” — closer to $70 to $75 per barrel, they say.

In the Eagle Ford, RBC expects production growth to soften somewhat, despite an increasing well count from 2014 to 2017. “This is partially because new drilling has to offset increasingly larger base field declines, but we also expect that the majority of Tier 1 oil acreage will be drilled by 2016,” the analysts say. Furthermore, locations remaining through 2020 will be gassier.

They believe the majority of drilling efficiencies in the play will have been realized by the end of this year, with days per well declining from 29 in 2011, to 19 in 2013 and leveling off at 17 days in 2016. Some 18% of the hydraulic horsepower in the U.S. is in the Eagle Ford, and the average price per stage has fallen by 36% in the past year, with the average number of frac stages increasing by 24%. Take-away will still be about 30% ahead of production by 2018, according to the report.

Breakevens in the Eagle Ford range from as low as $45 per barrel, in the best areas, to as high as $80 on the fringe. The basinwide average is about $65. The RBC analysts think activity would withstand prices as low as the mid-$80s, but in the weaker areas would drop off below that. Oil prices below $70 would halt activity.

Bakken oil production will nearly double by 2018, to 1.65 million barrels per day, according to RBC’s outlook. As in the Eagle Ford, most drilling efficiencies will have been realized by 2014, with days per well declining from 31 in 2011 to 21 days this year, leveling off at 20 days in 2015.

Who will be best positioned to withstand crude price declines, should they arrive? “Size and scale often bring with them inherent advantages regardless of industry — more negotiating leverage with suppliers, a better integrated and more efficient logistical network and pricing power with customers,” the analysts say. “In a world of rapidly growing domestic light oil production, we believe these latter two relative advantages will be of paramount importance in the E&P space over the next few years.”

Market savvy will also come into play, as the near-term balance of power continues its shift “from producers to refiners, especially in the Gulf Coast.

“Additionally, we believe rising domestic oil production lends itself to more frequent and more severe regional price dislocations. As a result, E&P companies that are more nimble in their ability to find alternative outlets for their crude are at a relative advantage to their peers.”