The Barnett shale has been the centerpiece for pioneering in American shale gas plays and the development of horizontal unconventional drilling technologies. Originally thought to hold an estimated 327 Tcf of gas in place, 44 Tcf of which was deemed recoverable, the play has a long production future.
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Just how this future will look, however, is subject to the economics for natural gas and especially the returns that the Barnett shale can offer in comparison with its peers. An examination of the future of the Barnett from the vantage of an investor reveals why it might be a good investment in the future.
The Barnett is in the Forth Worth Basin in Central Texas, spanning 10 counties for an area of approximately 5,000 sq miles (12,950 sq km). The Barnett shale currently produces 5 Bcf/d, based on data from the Railroad Commission of Texas, above its peak of 4.45 Bcf/d in October 2008. As a result of the 59% decline in natural gas prices, the rig count has declined to 82 currently from its peak of 174 in 2Q 2008. The rig count was 67 at the beginning of the year and has risen, largely due to focus on liquids-rich parts of the play.
The core area (where economics of wells are the most rewarding) now is believed to be in Johnson and Tarrant counties, with some areas of Denton and Wise counties believed to have similar economics. Tier 1, which lies to the south and west of the core areas, is somewhat less economic (gas-price sensitive) and generally lacks the Viola limestone that separates the Barnett from the underlying water-bearing formations that can present more challenges.
The Mississippian-age shale lies between the Marble Falls limestone (6,500 ft or 1,981 m depth) and the Chapel limestone (8,500 ft or 2,591 m depth), ranging in thickness from 100 to 600 ft (30 to 183 m). Within the formation, the Barnett has one of the highest gas contents, ranging from 300 to 350 cf/ton of rock.
The best economics to be found in the play lie in the core, followed by the Tier 1 area, and then Tier 2 (which is not expected to be developed in the next five years to a material degree). Tier 2 acreage primarily is in Erath, Jack, and Palo Pinto counties. Well spacing ranges from 60 to 160 acres per well. Nearly 11,000 wells currently are producing from an average depth of 7,500 ft (2,286 m). This accounts for more than 7% of total domestic gas production.
Barnett wells start being economic at US $5.50/Mbtu gas prices. At $6 gas, core horizontal wells generate returns of 43%, and verticals show returns of 19%. In Tier 1, horizontals can generate a return of 34%. Even at $5, returns come to 17%. What this means is that the Barnett can be a major player.
A North American shale giant
Key to making the economics of the play work was the introduction of large-scale hydraulic fracturing, a process that developed in Texas in the 1950s and was first used in the Barnett in 1986. The first Barnett horizontal well was drilled in 1992. Through continued improvements in the techniques and technology of hydraulic fracturing, development of the Barnett shale has accelerated. In the ensuing two decades, the science of shale gas extraction has matured into a sophisticated process that uses horizontal drilling and sequenced multistage hydraulic fracturing technologies. The combination of sequenced hydraulic fracture treatments and horizontal well completions has been crucial in facilitating the expansion of the Barnett.
Prior to the successful application of these two technologies in the Barnett shale, shale gas resources in many basins had been overlooked because production was not viewed as economically feasible. The low natural permeability of shale has been the limiting factor to the production of shale gas resources because it only allows minor volumes of gas to flow naturally to a well bore. The characteristic of low matrix permeability represents a key difference between shale and other gas reservoirs. For gas shales to be economically produced, these restrictions must be overcome. The combination of challenging economics and low permeability of gas shale formations historically caused operators to bypass these formations and focus on other resources.
The economics of the Barnett has lured bigger operators to invest. One recent development of interest is the increase in mergers and acquisitions activity as Eni Spa, EOG Resources Inc., and others have sold properties in the play for between $14,000 and $70,000/acre, illustrating the difference between core and non-core acreage as well as the value of the optionality underlying the basin once prices recover.
The Barnett’s key competitive advantage as prices rise is its infrastructure in place and the high visibility of E&P companies in the play. Unlike the Marcellus shale, where gas-on-gas competition likely will keep some players from expanding their footprint, the Barnett is locked and loaded for production.
With more than 100 operators in the play, production will flow seemingly overnight when gas prices rebound. Likewise, there is less to worry about in older plays like the Barnett than in the relatively new Haynesville and Marcellus, as operators have both data points and drilling experience to guide their development.
So which operators give the best upside exposure to the Barnett? Devon Energy Corp., following its purchase of Mitchell Energy, drove the play forward more than anybody else and has more than 80% of its gas coming out of the play covered under firm transportation contracts. Devon holds acreage with approximately 5,750 undrilled risked locations, amounting to an approximate 8.4 Tcf of probable and possible risked resources and 41 Tcf of unrisked resources.
What really puts Devon ahead of the game, though, is its gathering system, as it owns 3,100 miles (4,989 km) of pipeline and seven gas processing plants in the area. Combined with Devon’s improved economics (drilling days down to 15.8 in 2008 from 33.4 in 2004), the gathering system makes Devon a top pick for exposure to the Barnett. Its high net revenue interest (an average 81%) allows the company to drill at lower gas prices relative to newcomers to the play. With current low gas prices Devon is not increasing its activity despite its 7,000 drilling locations. Nearly 40% of those locations are estimated to have high-value liquids. The company has tentative plans to expand its liquids processing capacity at Bridgeport. Its low average lease cost, increased focus on completion efficiencies, and pad drilling provide another boost to its economics.
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