Fayetteville Revisited

As one of the initial trendsetters in what has become a phenomenal success story of highly productive shale-gas plays across the U.S., the Fayetteville shale continues to kick out copious volumes of natural gas. According to Lawrence Bengal, commissioner of the Arkansas Oil and Gas Commission (AOGC), the play produced a total 1.604 trillion cubic feet (Tcf) from 2004 through November 2010. Gross daily production in November was 2.341 billion cubic feet (Bcf). Southwestern Energy Co. initially recognized the economic viability of the Fayetteville in 2002, ultimately establishing itself as the first operator in this shale resource.

The Mississippian-age Fayetteville shale occurs in the Arkoma Basin and extends across northern Arkansas from the western edge of the state throughout the north-central region, with an aerial extent of about 5,000 miles. The shale facies ranges from 50 to 500 feet in thickness and varies in depth from 1,500 to 6,500 feet. The deposit is bounded by the Pitkin limestone above and the Batesville sandstone below; it is the geologic equivalent of the now-famous Barnett shale in Texas.

Lawrence Bengal, commissioner of the Arkansas Oil and Gas Commission, says the play produced a total 1.604 trillion cubic feet (Tcf) from 2004 through November 2010.

In fact, Fayetteville development was encouraged in large part because players recognized parallels between this shale and the prolific Barnett. Lessons learned from the horizontal-drilling and hydraulic-fracturing techniques used in the Barnett were key to making the Fayetteville economic.

Between 2004 and 2007, the number of gas wells drilled annually in the Fayetteville catapulted from 13 to more than 600, and gas production soared from a tad over 100 million cubic feet (MMcf) annually to about 88.85 Bcf per year, according to the U.S. Department of Energy’s Shale Gas Primer, April 2009.

The primer noted that the gas content of the Fayetteville (60 to 220 standard cubic feet per ton) is less than the Barnett (300 to 350 scf per ton). This leads to lower estimates of the original gas-in-place and technically recoverable resources for the Fayetteville, of 52 Tcf and 41.6 Tcf, respectively, compared to 327 Tcf and 44 Tcf for the Barnett.

Many industry participants consider the Fayetteville shale to be a world-class reservoir, owing in large part to the application of horizontal drilling and multistage fracing. The U.S. Geological Survey’s 2010 Assessment of Undiscovered Natural Gas Resources of the Arkoma Basin Province and Geologically Related Areas estimates the potential undiscovered petroleum resources in two of the three Fayetteville assessment units to be 13.2 Tcf of natural gas.

This makes it all the more puzzling that the Fayetteville play seems to have become a virtual footnote in the much-publicized overall shale-gas story.

The relative lack of recent coverage may stem in part from the fact that the Fayetteville became a shale-gas play before unconventional plays rocketed to fame. New fields in varying geographic areas were tapped in fairly rapid succession, with each being hyped as the greatest happening since cold beer.

Additionally, prices hovering in the range of $3+ per Mcf today have knocked shale gas off its pedestal—for now—and some operators have done an about-face, chasing the liquids-rich deposits that are so alluring in this latest heyday of high crude oil prices.

Whatever the reason, a number of players are shedding at least a portion of their shale-gas assets, including the Fayetteville, opening up opportunities to others waiting in the wings for the right deal.

ExxonMobil made a significant statement about its hunger for shale gas when it gobbled up unconventional-resources player XTO Energy in 2010 for $41 billion. Soon afterward, XTO swooped in on big-time shale player Petrohawk Energy Corp.’s Fayetteville gas assets, located principally in Cleburne and Van Buren counties, Arkansas, forking over $575 million to consummate the deal, which was effective October 1, 2010. At the close of 2009, Petrohawk’s estimated proved reserves in the Fayetteville were some 299 Bcf. Additionally, the two companies entered into an agreement for XTO to purchase Petrohawk’s Fayetteville midstream assets for $75 million.

High-profile natural gas aficionado Chesapeake Energy Corp. has seemingly been everywhere in the shale-gas milieu. But money talks, and the company is busy adding liquids-rich plays to its portfolio. Still, it surprised many in the industry when the company, which is the second-largest gas producer in the Fayetteville, announced early in February it would sell its assets in the play. Just a couple of weeks later, a buyer for the company’s interests in approximately 487,000 net acres of leasehold and producing properties was announced: BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Ltd., Australia.

The deal is the largest North American E&P divestiture of the past 10 years, with a reported sales price of $4.75 billion cash. Current net production of 415 MMcf equivalent of gas per day is included, along with midstream assets containing 420 miles of pipeline. Chesapeake will provide essential services for BHP Billiton’s Fayetteville properties for up to one year for a designated fee.

The buyer appears smitten with the opportunity to get in on the play, which will immediately add more than 10 trillion cubic feet of gas resources to its portfolio, catapulting the company seemingly overnight into a position as a major North American natural gas producer.

“The Fayetteville shale is a world-class onshore natural gas resource,” said J. Michael Yeager, chief executive of BHP Billiton Petroleum, in announcing the transaction. “It provides access to a competitive long-life resource basin that benefits from our ability to invest through the economic cycles.” BHP will invest as much as $1 billion annually over the next decade.

Wells Fargo analysts put the deal’s metrics at $9,036 per Mcf equivalent per day, or $1.52 per Mcf equivalent for the proved reserves. On an acreage basis, the deal brought an “attractive price” of $7,700 per acre, say the analysts.

Play Founder

Aside from these changes, there is a significant constant in the Fayetteville shale play—founding operator Southwestern Energy Co., which continues to drill and produce Fayetteville shale gas, and happily so. Its position as the biggest producer in the play is conducive to being happy.

The company’s Fayetteville leasehold tops out at 915,884 net acres, and production for 2010 tallied 350.2 Bcf net, up from 243.5 Bcf in 2009, according to financial and operating results for the fourth quarter and the year ended December 31, 2010. This represented a big chunk of Southwestern’s total gas and oil production of 404.7 Bcf equivalent in 2010, up 35% compared to 300.4 per Bcf equivalent in 2009. The company’s average realized gas price was $4.64 per Mcf, including the effect of hedges, in 2010, compared to $5.30 per Mcf in 2009.

At year-end 2010, Southwestern had spudded a total 2,001 operated wells in the Fayetteville since the play commenced in 2004. A total 1,820 operated wells had been drilled and completed overall, which included 1,730 horizontals. The company added approximately 1.6 Tcf in new reserves in the shale drilling program during 2010 at a finding and development cost of $0.86 per Mcf. In 2009, new reserves tallied 1.8 Tcf with finding and development cost at $0.69 per Mcf.

Southwestern’s total proved net reserves booked in the Fayetteville shale at year-end 2010 were 4,345 Bcf (4.3 Tcf) from a total of 3,682 locations. Of these, 2,120 were proved developed producing, 36 were proved developed non-producing and 1,526 were proved undeveloped. Current daily production stood at 1.6 Bcf on a gross basis at year-end.

These are certainly respectable numbers, but may only hint at what’s to come.

“There are still misconceptions about this play,” says Alan Stubblefield, senior vice president at Southwestern.

“We’re still in the early innings of the ball game,” says Alan Stubblefield, senior vice president, Southwestern Energy Co.

“We’re still in the early innings of the ball game. Large portions of the program in the last two years were dedicated to earning our acreage, but we’re now getting to the stage where we’ll be able to start exploiting some of the infrastructure and operational efficiencies we’ve been building. The majority of this year’s planned wells will be starting to see the benefits from some of what we’ve been building over the last several years.”

The company continued to improve its drilling practices in the Fayetteville in 2010. During the fourth quarter, operated horizontal wells had an average completed cost of $2.7 million per well ($2.8 million in the third quarter), average horizontal lateral length of 4,667 feet (4,503 in the third quarter) and average drilling time to total depth of 8.2 days (11 days in the third quarter) from re-entry to re-entry.

Number of wells per pad site is estimated to be 2.3 wells per pad in 2011 with a goal to eventually transition to as many as 10. Vertical well depth ranges from 1,500 feet in the northern part of the play to 6,500 feet in the southern area.

Southwestern ranks among the lowest-cost producers in the play in terms of finding and developing reserves and operating wells, according to Stubblefield. “We have a great resource to develop, great people to conduct our operations and integrated services that help save us about $225,000 per well. We own 15 rigs, of which 13 are operating in the play,” he notes.

“Two of these are smaller for drilling the vertical section of the wells. Also, we own a frac sand plant in the north Little Rock area where we manufacture our own sand for the fracture stimulation of our wells; the sand source is an old point bar off of the Arkansas River.”

Currently, Southwestern has 20 rigs running in the Fayetteville area, down from 24 at the end of July 2010. Twelve of these are capable of drilling horizontal wells, with eight smaller rigs to drill the vertical part of the wells.

Fayetteville operators benefit from a ruling by the AOGC that allows for maximum development on the perimeter of each section. They can drill cross-unit wells, and there’s a sharing formula in the rules for sharing production across these unit lines. “Some states create special drilling units for the long laterals, and others limit the laterals because they want to stay with their spacing, so states handle that longer lateral length differently,” says Bengal at the AOGC.

“Because of this ruling, we’re able to contact and produce a lot more gas than if we couldn’t drill cross-unit wells,” notes Stubblefield. “It’s a great benefit to royalty interest owners, the state and the companies drilling wells.”

Rig counts in the Fayetteville are down, but new entrants to the play may help shift those numbers upward.

When queried about the trend to restricted-rate production in the Haynesville shale, where wells are brought on line via smaller chokes to better control initial producing rates, Stubblefield explains that this is unnecessary in the Fayetteville. “The Haynesville is geopressured, and that may impact the benefit being seen there. We’re in a slightly underpressured to normally pressured environment, so we don’t see any benefit for doing that.

“We continue to look for ways to improve completions and the amount of gas we’re getting from each well from the fracture-stimulation process,” Stubblefield adds. “It’s working very well today, but we are always looking for ways to improve our margins on both the cost side and the recovery side.”

When pressed to provide even a guesstimate for Southwestern’s total gas recovery from the Fayetteville when all’s said and done, Stubblefield simply says, “It’s a big number.”

In a recent research report, Nicholas Pope, an analyst with Dahlman Rose & Co., forecast what Southwestern will need to spend, and the drilling rate it will need to maintain, to replace production declines in the Fayetteville.

“Each month, we are assuming Fayetteville shale production will decline at a rate of 1.5% per month,” he said. “Based on the current gross production rate of 1,500 MMcf per day, production will likely drop by 27 MMcf daily over a month, which needs to be replaced with newly drilled wells in the same month to keep production flat.

“The company is seeing average 30-day rates of between 2.4 and 2.5 MMcf daily currently, which matches our historic data. So, we are assuming it will need to add 22.5 wells per month to replace this production if the wells come online at the midpoint of the month. The wells are currently costing $2.8 million per well. So, the company will need to spend $63 million per month to replace declining production.

“That means to replace declining production in the Fayetteville and keep production flat, the company will need to drill 270 wells, and spend $756 million over the course of the next year.”

Meanwhile, as Fayetteville production has ramped up, legacy pipelines in the area became insufficient to handle the increasing product volumes. This resulted in two new significant export pipelines.

Boardwalk Pipeline Partners LP built two laterals to transport gas from the Fayette­ville shale area to markets directly and indirectly served by their existing interstate pipelines. The 165-mile, 36-inch Fayetteville lateral reportedly has a peak day capacity of 1.3 Bcf. Peak day capacity for the 95-mile, 36-inch Greenville lateral is said to be about 1 Bcf. The Greenville lateral will enable customers to access additional markets, mainly in the Midwest, Northeast and Southeast.

As well, Kinder Morgan Energy Partners LP and Energy Transfer Partners LP have just completed their 50-50 joint venture, Fayette­ville Express Pipeline LLC, a 187-mile line to move shale gas to market. It originates in Conway County, Arkansas, and ends at the interconnect with Trunkline Gas Co. in Quitman County, Mississippi. With an initial capacity of 2 Bcf per day, FEP has already secured binding, 10-year commitments totaling 1.575 million dekatherms per day, including 1.2 million per day from Southwestern Energy.