The industry will be able to respond to market changes quicker than other sectors which has partly contributed to the US becoming a “swing producer”

As technology forges ahead to diminish drilling times, IHS said this week that in terms of operators, “the survivors of this downturn are likely to be better off than before because they will be eliminating unnecessary costs and inefficiencies, creating stronger organisations”

That list, however, is trimming by the day.

The latest was Linn Energy, which filed for chapter 11 bankruptcy on Wednesday after reaching a deal with lenders to restructure its $US8.3 billion ($A11.35 billion) debt and obtain $2.2 billion in new financing.

This follows Houston-based Ultra Petroleum and Oklahoma-based Midstates Petroleum – two publicly traded oil and gas companies which have combined debt loads of more than $5.8 billion – separately filing for court protection in US Bankruptcy Court in Houston in the past fortnight.

That was after upstream company Energy XXI filed for chapter 11 bankruptcy protection on April 14 with $2.9 billion worth of debt.

Perth-based independent analyst Peter Strachan told Energy News that the US shale revolution was driven by “cheap money”, as interest rates were so low and every year producers were just raising more money and weren’t making any free cash flow.

“For the last 4-5 years the debt burden of all these companies has gone up,” Strachan said.

“The US shale producers increased production by 4MMbopd from 2010-2015, driven by cheap money, so the Saudis tightened the noose, pushed all these US companies out of business, even though they claim low cost, as they simply can’t cover the cost of servicing their debt.”

The best example is diversified miner BHP Billiton’s light, tight oil business in the US, which saw it spend some $2 billion more than the business was spitting out every year to develop it.

“That business was producing about 340,000boepd and was generating $2 billion of operating cash flow, but then were spending $4 billion every year to develop it,” Strachan said.

“So effectively they had to spend $2 billion a year – and this was when the oil price was $110/bbl and gas was $3.50, so it’s a very hungry business. If they stop spending and re-invest that $2 billion, then that business would’ve eventually shrunk.

“You need to spend at a faster rate because of the fast rate they come on, then drop right down to keep production even steady.

“Obviously the shale oil people will start to drill when it gets over $50/bbl as they can cover costs at that point.”

Timing is everything

Meanwhile, those who are able to leverage new technologies to their advantage and time their production to survive the downturn are reaping the rewards.

IHS said that while US oil and gas operators with significant inventories of drilled but uncompleted wells in the major US plays would benefit from capital efficiency gains this year, converting these wells to production would barely dent overall US production compared to US production growth derived from new drilling activities.

IHS defines a DUC well as a location where the well has reached target depth, but has not been completed.

IHS senior director of energy research for the North America Onshore Service, Stephen Beck, said that while the overall production implications for US supply are relatively small, on a company performance level these DUC wells were “critical” to the operators that have them in their 2016 inventory because they would deliver production and significant capital efficiencies.

Beck, lead author of IHS’ latest DUCs analysis, Drilled but Uncompleted Wells – FIFO Practices Provide Order in Uncertain Times, said his firm estimates total spending to convert all existing DUCS to production is about $11.5 billion.

This represents a 40% savings of the capital it would require to drill and complete a new well.

“In this low-price environment, that is a significant savings for operators who have DUCs in their inventories,” Beck said.

Anadarko and EOG Resources are two of the few known operators who employ a “drill and hold” strategy and intentionally accumulated DUCs to shape growth when oil and gas prices rise, opting to keep drilling wells with rigs that were under contract rather than terminate the contracts and defer the completions of those wells.

IHS estimates production to be derived from roughly 2750 net remaining DUCs will be more than 380,000bopd by September 2017 – just 16% of the estimated US oil wedge production volume of 2.45MMbopd.

For natural gas, IHS estimates production will peak at 3.5 billion cubic feet per day in October 2017, accounting for only 19% of wedge volumes of 18.58Bcfpd.

Beck said that to optimise their pad drilling efficiencies and minimise risk, oil and gas operators typically drilled all the wells on one pad then move to the second and third pads, if present, and do the same until all wells are drilled.

The operators would then proceed with the completion process.

“Drilling all the wells at once enables operators to negotiate better rates with service companies, who in turn, get the benefit of larger projects, but this leads to a batch-processing nature. This batch processing results in the formation of these DUC wells, but it also drives a natural delay as it relates to the completions of these DUCs, which also follow in batches,” Beck said.

Most importantly, he said, the delayed conversion of DUCs to producing wells in the last few years explains the resiliency in US production, and in part accounts for its recent recognition as the world’s new ‘swing producer.’

“The US energy system doesn’t turn on a dime, but it does turn faster than an oil tanker,” Beck said.

“It can respond to changes in price in less than a year, which is not the case for other resources elsewhere.”