CERA: Rising gas production costs diminishing returns
Fewer natural gas reserves are being added for every dollar spent on exploration and production, and higher costs are undermining the economics of drilling more gas wells, Cambridge Energy Research Associates said in a recent report.
By OGJ editors
HOUSTON, Feb. 2 -- Fewer natural gas reserves are being added for every dollar spent on exploration and production, and higher costs are undermining the economics of drilling more gas wells, Cambridge Energy Research Associates said.
"Conventional wisdom is that all producers are enjoying a windfall from higher prices; however, the less-visible cost of gas production has moved up as dramatically as market prices," said J. Michael Bodell, CERA director, upstream gas strategies.
The report, "Diminishing Returns," analyzed full-cycle costs for wells drilled in 2005. The study also identified a shift toward unconventional gas production, now accounting for 25% of total US and Canadian gas production.
CERA used statistics from its parent, IHS, to analyze costs and production rates for 48,000 wells completed in 50 US and Canadian gas basins (232 individual plays) in 2005. Researchers found capital costs (excluding operating costs, royalties, and return) were $1-6/Mcf.
The weighted average all-in cost was from less than $4/Mcf to more than $12/Mcf. Judged against record 2005 gas prices averaging $8.80/Mcf at Henry Hub, more than 6% of basins had high enough costs to prevent a 10% rate of return-on-investment.
More wells, flat production
"Record prices in 2005 triggered a tremendous response in drilling by gas producers, leading to nearly decade-high reserves additions of 26.4 tcf and added production of 14.7 bcf that year," Bodell said.
Yet production remained flat despite more rigs drilling during the past decade, he said. Meanwhile, the cost of new gas supply rose due to higher drilling and operating costs as well as declining average well productivity and initial production rates.
"The ultimate economic performance of the wells drilled in 2005 will depend on the trajectory of market prices and many other factors related to well production," Bodell said. "However, viewed in the context of the market and cost environment at the time of drilling, it is clear that rising service costs have begun to take away much of the margin in many wells and plays despite historically strong market prices."
Record well completions are being totally offset by declining well productivity, and price expectations will be key to motivate continued strong drilling, Bodell said.
"The fundamental driver of the North American E&P challenge is the relative maturity of the natural gas resource base," he said. "Although gas resources are available—and some are off limits due to access issues—and new plays are being identified and developed, many of these resources are deeper, smaller, technically more challenging, or more distant from markets."
The study found E&P companies are developing smaller resources and facing higher costs, with the inevitable result of increased unit costs. Within this overall trend, many regions still reported strong margins and provide returns on equity of well above 10%.
"The E&P companies that have shifted their portfolios to include these lower-cost resources, particularly the early movers, are recognizing substantial cost advantages," Bodell added.
The study also said producers have heightened drilling levels to replace gas lost from production declines in wells drilled during previous years.
"If no further drilling occurred after 1999, North American wet gas production would have fallen to about 29 bcf by 2006, or less than half the production level in 1999," Bodell said.
Shift to unconventional gas
The CERA-IHS analysis found higher prices combined with improved drilling and rock fracture technology has accelerated development of unconventional resources, which accounted for 23% of total US and Canadian gas production in 2005. That compared with 11% in 1995.
Unconventional gas has been generally more costly to develop than conventional gas until recently. Because these resources have lower per-well flow rates and require more wells in a given area to maintain a given supply level, gas production rates for wells added in 2005 were about half that of wells drilled 10 years earlier.
However, because unconventional wells access larger deposits than their conventional counterparts, they accelerate reserve growth and provide higher production over a well's 20-year life.
"On the question of whether unconventional gas is cheaper or more expensive than conventional resources, we found there is no consistent answer," Bodell said. "Unconventional production basins are distributed throughout the cost spectrum among the lowest and the highest cost resources, and not overweighted on either the low or high end."
Industry is investing heavily in unconventional resources, moving from the easier plays and basins to more challenging opportunities, he said.
"These more challenging resources may come at a cost that has the potential to put them in direct competition with imported LNG," Bodell said.