Southwestern Energy Slashes Fayetteville Shale Budget

A top Wall Street analyst said the Fayetteville Shale and other aging dry gas shale plays have had a good run over the past several years, but added “they can’t compete” with shale plays that produce both crude oil and wet natural gas.

Oppenheimer Managing Director Fadel Gheit provided his analysis of the Fayetteville Shale as Southwestern Energy Corp. and BHP Billiton have drastically cut their investments in the Arkansas shale play.

Southwestern recently announced it was cutting 40% of its investment in the unconventional Arkansas shale play. BHP has also cut its budget in the Arkansas shale play to only $100 million – a fraction of its original spending plans when it bought those assets for $4.75 billion in 2011.

“The Fayetteville (Shale) and other dry gas plays have done remarkably well given the low gas prices for over five years, but they cannot compete with liquids rich plays,” Gheit said of the Arkansas play’s near-term prospects. “Given the current low oil and gas prices companies have cut spending and whatever left will be allocated to the most profitable plays.”

Wet gas is natural gas with a small amount of liquid present. It contains additional compounds that can make the extracted gas more versatile in its use.

According to the U.S. Energy Information Administration (EIA), the number of wells drilled nationwide that produce both oil and natural gas increased from 37% in 2007 to 56% in 2012. Higher drilling efficiency and new well productivity, rather than an increase in the rig count, have been the main drivers of recent production growth, the EIA said.

Currently, six shale plays account for nearly 90% of domestic oil production growth and virtually all domestic natural gas production growth over the last few years. The Bakken Shale in North Dakota and Eagle Ford play in Texas account for about two-thirds of oil production growth, the EIA said. The Marcellus dry gas play in Pennsylvania accounts for about three-quarters of natural gas production growth.

Overall, the Fayetteville Shale is now the fifth largest dry shale gas producer, behind the Marcellus, Eagle, Haynesville and Barnett. From 2002 to 2010, the Barnett was the most productive source dry gas shale play in the U.S., but its future development has been slowed because of its location in fast-growing urban areas in the Dallas-Ft. Worth metropolitan area.

CAPPING CAPITAL SPENDING
Gheit, who has been named to The Wall Street Journal All-Star Annual Analyst Survey four times and was the top-ranked energy analyst on the Bloomberg Annual Analyst survey for four years, said the only real hope in the near-term for a dry shale play comeback is if natural gas futures come out of their current slump.

“Most of these (dry) plays would attract more capital at gas prices above $4.50 per million cubic feet (Mcf),” said the Wall Street oil and gas forecaster.

Higher natural gas prices, however, are currently not in anyone’s forecast, Wall Street or otherwise. According to the EIA’s most recent short-term forecast, the Henry Hub natural gas spot price is expected to average only $3.05 per million British thermal units (MMBtu) in 2015 and $3.47 per MMBtu in 2016.

It is those same depressed natural gas prices that have forced Fayetteville Shale leader Southwestern Energy to revise its previous 2015 capital spending and production guidance, cutting nearly $600 million from the Houston-based driller’s earlier budget projections in December and dramatically downsizing its investment in the Arkansas shale play.

According to the company’s most recent quarterly corporate filing, the Houston-based drilling now expects that its total capital investments for the full year of 2015 to be nearly $2.0 billion. That is 23% lower than its $2.6 billion forecast at the end of last year.

Of that total, the company’s newly acquired assets in Pennsylvania will get the lion’s share of the capital investment with nearly $1.22 billion off the top. That outlay in the Pennsylvania oil and gas shale play will be divided with $700 million targeted for drilling in the northeast Appalachia region of the state, and the remaining $520 million set for the southwest Appalachia region.

The budget for the Fayetteville Shale region was slashed by $284 million, down nearly 41% from the oil and gas firm’s previously announced December forecast to only $560 million for fiscal 2015. That is the lowest capex investment for the Arkansas shale play in nearly a decade.

Despite the austere budget measures, the company said it achieved record Fayetteville Shale production of 494 billion cubic feet of production in 2014, generating over $300 million in excess cash flow to reinvest in other growth areas of the company, Southwestern officials said.

“In the play’s tenth year of development, the (Fayetteville Shale) division continues to learn and apply those learnings to build on the past results to make them even better,” company officials said in the quarterly 10Q filing.

A CONTRAST
The news of the Fayetteville Shale downsizing dramatically changes the future prospects for the middle-aged Arkansas shale play. In October, Southwestern officials touted the Texas driller’s investment of more than $10 billion in development into the Arkansas shale play over the past decade.

Southwestern’s capital investment, company officials said, is also largely responsible for making Arkansas one of the top natural gas producers in the U.S.

“Arkansas is where it all started,” Southwestern Energy Chairman and CEO Steven Mueller told the cheering employees at the company’s 10-year anniversary celebration in Conway.

“This is certainly a milestone in the development of the play, and I’m proud of our role in its discovery and production,” he said. “Our work together in the Fayetteville Shale play has helped make us a strong company and put the state on the map as a major contributor to the country’s energy supply.”

At the same event, Southwestern’s newest Fayetteville Shale executive quashed any notions that the company’s natural gas wells in Arkansas have run dry.

“There is a lot left. We are going to be here for a long time,” said Paul Geiger, senior vice president and head of Southwestern’s Fayetteville Shale operations, told Talk Business & Politics in October.

Today, Southwestern still remains the largest producer of natural gas in the Fayetteville Shale where the company’s Arkansas workforce is focused on the development of the company’s 905,684 net acres. As part of its $10 billion investment in the project since 2004, the company has drilled more than 3,500 wells by the end of 2013.

But everything changed in late October when Southwestern first announced that it had agreed to purchase natural gas and petroleum liquids assets in the Marcellus and Utica shale plays for $5.4 billion. The seller in that deal was also Oklahoma City-based Chesapeake Energy, formerly the nation’s largest oil and gas driller that sold its holdings in the Fayetteville Shale to BHP three years ago for about the same price.

Following the deal, at least five analysts covering the Fayetteville Shale leader upgraded the company’s shares and gave the driller’s stock a “buy” rating. Most applauded the deal at the time because it gave Southwestern access to shale plays with access to higher priced crude oils, which were then trading at nearly $85 per barrel.

A GROWING LIST
Southwestern Energy is not alone in its capex reductions. Exxon Mobil, the world’s largest publicly-traded oil company, also announced Wednesday that it was cutting its budget by 12% to $34 million. The Irving, Texas-based oil giant also said it does not plan to increase its capital budget in the foreseeable future. Exxon Mobil rivals, Chevron, ConocoPhillips and Anadarko Petroleum, have also previously announced double-digit cuts in capital spending in 2015 as U.S. crude oil prices continue to trade around $50 a barrel.

In addition, Talk Business & Politics recently reported that Australian mining giant BHP Billiton was unable to find a viable suitor for its Fayetteville Shale operations, and is no longer seeking to sell the conglomerate’s unconventional natural gas in play in Arkansas.

“We have concluded the marketing of our Fayetteville acreage and have decided to retain it within our portfolio to maximize value,” BHP Chief Executive Andrew Mackenzie said in the company’s half-year earnings report. “The longer-term development of the Fayetteville remains an attractive option and with the majority of our acreage held by production, we will continue to defer investment for value, consistent with our long-term outlook for gas prices.”

Like Southwestern, BHP has also recently revised its plans to cut the company’s U.S. shale budget substantially for the remainder of the year. In BHP’s half-year review on Feb. 24, BHP said it will speed up plans to reduce costs and invest in more profitable businesses by cuttings its previously announced U.S. shale capital budget by 50% from $4.2 billion to $2.1 billion.

By rig count, BHP said that it planned to cut the total number of operating drilling pads in the U.S. from 26 to 16. In the Fayetteville Shale, that current rig count is at “zero” and its operational budget currently around the $100 million level, BHP’s financial reports show. In the first half of the year, BHP drilled and completed 27 wells in the Arkansas play, down 45% percent from a year ago.

Originally, BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited, paid $4.75 billion in cash in early 2011 to purchase nearly 487,000 net acres of leasehold and producing natural gas properties from Chesapeake Energy Corp.

Exxon Mobil’s XTO subsidiary, the second-largest operator Fayetteville Shale, has been mostly quiet concerning its operations in the Arkansas shale play. In December 2010, Exxon Mobil paid $650 million to Petrohawk Energy Corp. for natural gas wells and pipelines assets in the Fayetteville Shale.

In announcing its budget cuts today, Exxon Mobil CEO said in a news release that the company’s long-term capital allocation approach hasn’t changed, but annual capital and exploration expenditures are expected to average less than $34 billion from 2016 to 2017.

“We are capturing savings in raw materials, service, and construction costs,” Tillerson said. “The lower capital outlook also reflects actions we are taking to improve our set of opportunities while enhancing specific terms and conditions and optimizing development plans.”

At the close of business Wednesday, light, sweet Texas crude climbed $1.01 to $51.53 on the New York Mercantile Exchange. April natural gas prices settled up 5.7 cents, or 2.1%, at $2.769 per million British thermal units.