Fewer natural gas reserves are being added in North America for every dollar of exploration and production (E&P) activity, and higher costs undermine the economics of an increasing number of wells, according to an analysis of full-cycle cost data for all wells drilled in 2005. Cambridge Energy Research Associates (CERA) and IHS also found a dramatic shift toward unconventional gas production, which two years ago already accounted for nearly 25% of total output.
The multi-client analysis, "Diminishing Returns," analyzed cost and production data for 48,000 wells completed in all 50 North American natural gas basins (232 individual plays) in 2005, the most recent year for which full data are available. Capital costs alone (excluding operating costs, royalties and return) ranged from $1.00/Mcf of reserves to more than $6. The weighted average all-in cost ranged from below $4/Mcf to more than $12. Judged against the record gas prices of 2005, which averaged $8.80/Mcf (Henry Hub), more than 6% of the basins' costs were high enough that they would have failed to achieve a 10% rate of return-on-investment, the study found.
"Record prices in 2005 triggered a tremendous response in drilling by gas producers, leading to nearly decade-high reserve additions of 26.4 Tcf and added production of 14.7 Bcf that year," said CERA's J. Michael Bodell, director, Upstream Gas Strategies. "Nevertheless, despite a nearly threefold increase in the number of rigs deployed to drill natural gas wells over the past decade, North American gas production has remained stubbornly flat, and the cost of new gas supply has risen substantially due to higher drilling and operating costs and, most significantly, declining average well productivity and initial production rates."
Costs in the study were calculated by using the entire IHS catalogue of North American well and production information. Capital and operating costs were calculated for each of North America's 232 plays, and the production profile of each play was uniquely modeled.
"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," said Bodell. "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. 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."
Bodell said record well completions "are being totally offset by declining per-well productivity, so price expectations will be central for motivating continued strong drilling. The fundamental driver of the North American E&P challenge is the relative maturity of the natural gas resource base. Although gas resources are available -- and some are off limits due to access issues -- new plays are being identified and developed, [and] many of these resources are deeper, smaller, technically more challenging, or more distant from markets."
Taken as a whole, the study found E&P companies are developing smaller resources and facing higher costs, with the inevitable result that unit costs have moved to a much higher range. However, within this overall trend, many regions, by contrast, have strong margins and provide returns on equity well beyond 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 noted.
CERA and IHS also documented the heightened levels of drilling required to replace gas lost from declines in production from wells drilled in 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," said Bodell.
The combination of higher prices and improved drilling and rock fracture technology also has accelerated the development of unconventional resources, which accounted for 23% of total North American gas production in 2005. In 1995, unconventional plays accounted for about 11% of total gas production.
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 base growth and provide higher production over a 20-year productive life.
"On the question of whether unconventional gas is cheaper or more expensive than conventional resources, we found there is no consistent answer," said Bodell. "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. This means that the industry is investing heavily in unconventional resources moving from the easier plays and basins to resources that represent more challenging opportunities. These more challenging resources may come at a cost that has the potential to put them in direct competition with imported LNG [liquefied natural gas]."
For more information on the report, visit www.cera.com .
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