Sponsored Content: Translating Cost Discipline Into New Reserves In A Low Price Environment
The sharp drop in commodity prices in 2014 has had a big impact on oil and gas producers’ profitability. Many companies have not seen a dramatic impact on reported volumes of reserves since the crash, but have seen a major drop in the net present value of their reserves, according to Sproule.
In the four years 2011-2014 the price of oil averaged between $93 and $95 per bbl—long enough for the industry to come to depend on what was thought to be the new normal.
Since the price plummet in mid 2014, crude oil has averaged less than $50 per bbl. According to Sproule’s August forecast, prices are not expected to climb to anywhere near the pre-2014 level over the next four years. Sproule does expect the price to climb steadily from $55 in 2018 to $73 in 2021, though punctuated by temporary ups and downs.
Offsetting the negative impact of the oil price drop on reserve volumes and values has been the significant capital cost and to a lesser degree operating cost reductions realized in recent years, said Cameron Six, Sproule president and chief executive officer.
There have been three major negative impacts on reserve volumes from the price decline, he said. Firstly, low margin new development opportunities—such as new thermal oilsands projects and high finding-and-development-cost new drilling—are no longer economic and have become contingent resources instead of reserves.
Secondly, low margin existing producing wells may now be uneconomic to continue producing and are no longer included as reserves.
And finally, the economic limit for existing producing wells is reached sooner, reducing the economic life and remaining reserve volumes on producing wells.
“Probably the most impacted are projects that are no longer economic amid the price drop because there is just not enough revenue to cover all the capital and operating costs, so they don’t go forward,” said Six. “Those typically are capital intensive projects that were fairly low return at higher prices—now at lower prices they are no longer economic.”
The industry has reacted to the price drop by focusing on cost reductions in existing operations (operating cost) and on capital cost reductions for new development opportunities. Capital cost reductions have been achieved by implementing efficiencies in development programs (drilling, completions, facilities and tie-ins) plus pressuring service company providers to reduce costs.
“Across the industry we have seen a bigger impact on the capital costs than on the operating costs,” Six said. “A lot of the capital costs are related to drilling rigs, completion equipment and related services and there has been a lot of pressure on the service industry to reduce those costs. Whereas on the operating side costs tend to be more fixed it’s not as easy to affect a reduction.
“Over the last three or four years we have seen capital costs for typical projects in Western Canada reduced on the order of 20 to 50 per cent, depending on the project—that’s a pretty big drop,” he added. “It has made a big difference in that activity that had been going prior to the price drop has continued in a lot of plays because the capital cost reductions have been significant enough that it is still economic to proceed.”
Companies are seeing improvements in both individual well productivity and overall program cost reductions through innovations such as pad drilling, he said. “In every play there has been progression of learning for such items as which type of fluid works best, how many fracture stages are completed, how far apart and how much sand is used.”
Reserves have therefore been able to be retained and, in a few plays, the reduction in capital costs have facilitated adding additional new reserves for development activities that previously were not economic and therefore not included as reserves.
The key for many industry players is to ensure that sustainable efficiencies have been achieved that will not be affected if prices recover and service company costs climb along with prices.
“A lot of companies are trying to realize cost reductions that will be long-term, not just related to putting pressure on the service companies to reduce costs. They would like to see cost reduction efficiencies in their drilling and completion programs that they can maintain even if prices recover and service costs climb,” Six said.
From a reserve dashboard perspective reserve volume decreases due to prices have therefore been avoided by most companies by offsetting the price impact with capital cost reductions and/or deferral of some activity for a few years with the expectation prices will recover enough to justify retaining future development programs.
A few companies with large undeveloped reserves related to future oilsands development or expensive dry shale gas development have seen reserve decreases as these volumes have moved to contingent resources due to economics and/or deferral beyond the five year project start-up window to be classified as reserves.
But in general the sharp focus on cost reduction brought about by the commodity price collapse has had a silver lining. “By driving a focus on cost reductions and efficiencies, it has enabled companies to retain their reserves or in some cases continue to increase them, which would have been a tough thing to accomplish under the cost and price scenario that would have been realized if they hadn’t seen the cost reductions,” Six said.
Sproule is a global energy consulting firm with a 65-year legacy of driving value for clients by helping professionals in the oil and gas sector make better business decisions—decisions that build sustainable prosperity from resource assets around the world. Sproule is anchored by deep geoscience and engineering expertise combined with a strong commercial understanding of energy markets. Headquartered in Calgary, Canada, Sproule has offices in Colombia, Brazil, and the Netherlands. Learn more at Sproule.com.
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