Onshore drilling efficiencies in domestic shale gas plays continue to increase, per-unit costs continue to fall, and together, they given a big boost to operators’ proven reserves, by one calculation.
Exploration and production (E&P) companies have as a primary mission continuously replenishing their reserves stores, either organically and through acquisitions, said Barclays Capital’s Biliana Pehlivanova and Shiyang Wang. Refilling gas stores had been a challenge until about 10 years ago as operators worked to replace the amount of gas they produced with new findings.
Shale gas changed the rules, giving E&Ps big targets and big production rates. However, there’s been an unexpected bonus: proved reserves also have been gaining at a much healthier pace than anticipated, said the analysts.
“Despite a significant increase in U.S. gas production, reserves have nearly doubled since the beginning of the last decade. In fact, in 2010, dry natural gas proved reserves were at the highest level in recorded history. The number of years of supply in proved reserves has also nearly doubled since the 1990s.”
Two years ago, the Energy Information Administration estimated that based on technological know-how and drilling economics at the time (when average gas prices were $4.36/MMBtu), “proved reserves were sufficient to satisfy about 13 years of natural gas consumption, compared with an average 7.8 years from 1979 to 2010,” said the analysts.
“Not only has the industry expanded its reserve base, but it has also become increasingly efficient at getting the gas out of the ground. Growing efficiencies and falling per unit costs mean that more reserves become economical to develop at a given commodity price. Proved reserves are also likely to grow in the coming years as a result of increasing gas prices, as we anticipate.”
The rate at which E&Ps replace reserves, or the reserve replacement rate, consistently has exceeded 150% in the past 10 years for the same sample of 17 large-cap E&P companies that Barclays covers. “In 2012 in particular, the weighted average replacement rate was 182%, compared with a 10-year average reserve replacement rate of 208%.”
It all comes back to the shale, said the analysts.
Shale gas reserves jumped from 23 Tcf in 2007 to 97 Tcf in 2010, a three-fold increase in just four years. Over that same time period, proved U.S. gas reserves that weren’t shale fell by 7 Tcf, reflecting “the discovery of new resources, but also the continued improvements in drilling technology, which have significantly lowered drilling costs,” said the Barclays analysts.
Reflecting their initial development, the Barnett Shale in 2010 had the largest amount of proven reserves, followed by the Haynesville and then the Marcellus, said the analysts. However, the Marcellus and other plays are gaining steam, particularly as E&P technology know-how becomes better.
“While data on regional average production costs are difficult to collect, producer reports provide a glimpse into the economics of different shale plays,” said Pehlivanova and Wang. They pointed to the ability of Southwestern Energy Co.’s Fayetteville Shale to sustain prices “near the $4.00/MMBtu level.”
“Meanwhile, another producer has indicated that using a $4.00 price deck, its Haynesville play would yield approximately a 40% internal rate of return [IRR] in its project economics, and also noted that $4.00-6.00 sustained price level would drive it to invest more in its dry gas opportunities.”
Encana Corp. is one one of the only gassy producers to publicly announce it was hoisting rigs in the Haynesville (see Shale Daily, Feb. 19). Exploration chief Jeff Wojahn said in February that Encana’s supply cost in the play would be “in that $2.50/Mcf range…What that means from the profitability point of view is using the flat $3.50 Nymex [New York Mercantile Exchange] price deck, we are able to achieve rate of return of approximately 30%.”
Most of the new volumes would begin in 2014. “Using a $4 price deck…the yield is approximately 40% rate of return into project economics. And that type of return would be reflective of what the current Nymex strip is for 2013.”
A Marcellus producer, said the analysts, also has indicated that the “IRR for a typical well is about 50% with gas prices at $4.00/MMBtu, while returns are expected to improve as future drilling is expected to have longer laterals and more stages. The same producer reported that its company-level all-in cost has fallen from $4.30/MMBtu in 2008 to $3.00/MMBtu, a 30% drop in five years.”
Beyond the big dry gas shales, producers also are seeing favorable returns in some of the liquids-rich gas plays, including the Pinedale Anticline (23% liquids) and Cana Woodford Shale (33% liquids), said the analysts.
“An average well at Pinedale for this particular producer exhibits a before-tax return of 38% at $4.50/MMBtu gas and $85/bbl crude oil pricing. In the Cana Woodford Shale play, its average well returns of about 23% before tax with a similar assumption on commodities pricing.”
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