With commodity prices showing signs of new life, fall’s arrival brings with it a sense of optimism for the indus¬try rather than dieback. There is hope that the OPEC meeting to be held later this month will forge a new floor for crude prices, and that stronger natural gas prices will linger.

The industry’s financial health is certainly better. Reserve-based lending—especially vital to smaller and private companies’ growth—is stabilizing. An early October report from Raymond James & Associates said that the current redetermination season would be a “nonevent” for most of the com¬panies the firm covers, with liquidity largely intact. By comparison, this past spring energy lenders reduced borrowing bases by 12% for the firm’s coverage universe and by 20% for the industry overall.

“In fact, for the first time in two years, we are projecting that bank price decks, on aver¬age, will be slightly higher than they were vs. the previous redetermination,” the report’s authors, led by Kevin Smith, said. “This is a drastically different scenario vs. the past three redetermination seasons, whereby the borrowing bases were slashed by nearly 30% on average.”

Raymond James divides E&Ps into two “buckets”—those who were able to partic¬ipate in the “staggering amounts of equity [raised] to finance deals and strengthen their balance sheets,” and those who did not have access to capital and had declining production and “deep-in-the-money” hedge roll-offs. This redetermination season could finally push some in the second group “over the financial cliff,” the analysts said.

“Our prospective fall bank price deck is roughly 4% higher in 2017 for both oil and gas and basically flat in 2018. Longer term, it’s slightly lower for oil while a bit higher for gas,” the report said. “But the main point is, it is roughly 87%/90% of the strip for oil/ gas in the near term, increasing at a rela¬tively constant 3% to 5% past 2020—mostly unchanged.”

This year’s big equity raises, often related to acquisitions, softened the impact of pro¬duction declines and hedge roll-offs. “Thus far in 2016, we have seen more than $23 billion in equity raised by U.S. E&P com¬panies, a substantial 77% increase over the $13 billion that we saw in 2015,” the analysts said. The total dollar volume of deals in the second quarter of this year was higher “than in any quarter dating back to just after the financial crisis in fourth-quarter 2009.”

Along with equity infusions, technology has helped E&Ps to survive by lowering operating costs during the downturn. But an early October Bernstein analysis of Barnett Shale horizontal performance indicates that “longer for lower” might be a tag line for laterals.

“The E&P narrative is that a revolution in technology of improved completions (more sand, water, clusters, geosteering, landing, etc.) is pushing down the cost curve. Yet we fail to see it in the most complete data record we have,” the analysts said.

On a per-foot basis, they said, “the Barnett got consistently worse with time.” The early, 2,000-foot laterals achieved peak monthly rates of about 500 barrels of oil equivalent per day. But even though producers dou¬bled lateral lengths, they haven’t been able to maintain that production rate. (Bernstein looked at all horizontal wells from the top four operators in the play: Chesapeake Energy, Devon Energy, EOG Resources and ExxonMobil.)

The analysts weighed factors that could still put a positive spin on results. Maybe lower peak rates were offset by better decline rates. If so, they figured that the “share of the peak month as a fraction of the first year’s production or first two years’ production would have significantly changed.” Instead, their data found the peak month responsible for “14% of the first year’s volumes and 8% of the first two years’ volumes, and effec¬tively flat over time.”

Or maybe increasing lateral length sim¬ply resulted in decreased rate of production per foot. This proved to be true. “Frictional losses along the horizontal wellbore increase with increasing length, and all things being equal, rate per foot drops with rising length,” the analysts said. “From an engineer’s per¬spective, so long as the incremental benefit of the longer lateral (in terms of more volume/ revenue) offsets the incremental cost, then keep increasing!” they said. Barnett oper¬ators stopped increasing lengths at about 7,500 feet.

Something else had to be standing in the way of gains from the technology and expe¬rience that operators have brought to bear in the shales. “In our view, that ‘something else’ is geology—the scarcity of high-quality loca¬tions and the desire of the industry to identify and drill the best locations first.”

This conclusion is bullish for longer-term oil prices, and for operators who hold the premium positions in the best resource plays. “If correct, we believe the implication is that shale is a scarcer resource than generally considered,” they said, “and thus [we] are more constructive longer-term as the world must seek a more marginal barrel to match future demand growth.”

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