April Industry Affairs

Big Wells Boost Company Performance


Adam Wilmoth, Published: April 7, 2017

Improved drilling and completion processes combined with favorable geology have led oil and natural gas companies to bring online a series of massive wells in central Oklahoma's STACK and SCOOP plays.

Big wells drive spending decisions for the well operator and for operators throughout the area. They also drive up interest in nearby acreage and sales prices throughout the field.

Enid-based Ward Petroleum last week boasted of a Grady County well that tested at an initial production rate of almost 16 million cubic feet per day of natural gas and 860 barrels of oil per day. The well was drilled into the Mississippian formation with a horizontal length of about 7,500 feet.

"For Ward, it establishes the reservoir and the opportunity in our SCOOP assets," said David Stone, Ward's chief operating officer. "We're very encouraged about the results."

Ward's Lynda well was drilled into the Mississippian formation, a rock layer that produces large amounts of saltwater in northwestern Oklahoma, but far less water in Grady County and other parts of the SCOOP.

"I've always believed the Mississippian has been an excellent target," Stone said.

With the success of the Lynda well, Ward likely will expand its drilling program in the area.

"This opens up the opportunity not just for us, but for the industry as well," Stone said.

Initial production rates can be difficult to compare. Some companies report the rate over the first 24 hours, while others average the production over the first 30, 60, or 90 days.

Collectively, though, they can show trends and provide a glimpse into the overall potential of a field or region.

Oklahoma City's largest publicly traded companies also are active in the SCOOP and STACK. They have boasted of similar successes in the region over the past few months.

Continental Resources Inc. in the fourth quarter of 2016 drilled seven STACK wells that had first 24-hour production test rates of more than 1,600 barrels of oil equivalent, including one well with an initial rate of 2,463 equivalent barrels per day.

Devon Energy Corp. in the fourth quarter had two operated wells achieve 30-day rates. They averaged 1,600 barrels of oil equivalent, including 70 percent oil, the company said.

Chesapeake Energy Corp. CEO Doug Lawler last month said the company recently drilled more than 10 central Oklahoma wells averaging 30-day initial production rates of 1,140 barrels of oil equivalent, including one that tested at 1,813 equivalent barrels per day and 80 percent oil.

U.S. Shale Investment Is Back On The Upswing


Shelley Goldberg Published: April 12, 2017

Global upstream oil and gas merger and acquisitions reached $136 billion in 2016, according to Evaluate Energy's global M&A 2016 review. And one area seeing a jump in activity was the U.S. Marcellus shale, where close to eight times more was invested in asset and corporate acquisitions in 2016 than in 2015.

The Marcellus formation, which runs through northern Appalachia, primarily in Pennsylvania, West Virginia, New York and Ohio, is considered the second-largest natural gas field in the world, after Northfield in Qatar and Iran. Marcellus spans approximately 60.8 million net acres with an estimated 500 trillion cubic feet of natural gas, about 50 trillion cubic feet of which is recoverable using current technology.

In 2015, the U.S. shale industry was one of the main casualties of the oil price downturn, suffering a 75 percent drop in year-on-year merger and acquisition spending to $13 billion. This amount was the lowest annual M&A U.S. shale spend since 2009. A reshuffling of asset portfolios in 2016 redirected investments away from the Permian basin, and toward the Marcellus Shale which, which led to resurgence in deals as well as natural gas output. The M&A spend in the shale industry bounced back to $48 billion during 2016, representing a 269 percent increase year on year.

Many of the players were eager to take advantage of other companies realizing that their respective Marcellus positions were noncore assets. Mega international players such as Anadarko Petroleum Corp., Statoil ASA and Mitsui & Co. Ltd. sold significant portions of Marcellus land for sums of more than $100 million. Southwestern Energy Company, in efforts to reduce debt, agreed a large deal to sell Marcellus acreage that had no drilling plans until 2023. The acquirers of these assets included far more Marcellus or Appalachian basin-centric companies.

Overall, the Marcellus 2016 deals totaled $7.25 billion. This kind of year-on-year increase usually reflects one or two mega deals but not in 2016, when the total included 13 large deals (over $100 million). Both figures are a significant increase on 2015 activity, when only $920 million was spent and only three large deals took place. In fact, 2016 saw more large deals in the Marcellus than in every year since 2010, the first real M&A boom, when 15 such deals were announced.

The Marcellus rig count, which had seen a precipitous drop from 2012-2015 finally swung upward. Despite the decline, new-well gas production per rig in the region had risen throughout that time, due to enhanced technology and hydraulic fracking, which also helped to revitalize much of the legacy gas production.

During the recent oil crash, oil-field and gas-drilling services providers had to reduce prices, in some cases, toward levels that would have made their businesses unprofitable. Now with drilling prices starting to stabilize and recover, according to Wells Fargo, the producer price index for well-drilling costs jumped 8.7 percent in February from the prior month, the biggest monthly increase since 2005. Prices spiked on an annual basis too, by the most since August 2014. 

The cost increase, nevertheless, is unlikely to stifle future production because, apart from the oil crash, there had been a structural decline in average drilling costs over the past few years. According to the EIA, costs per well increased from 2006 through 2012, a time of rapid growth in U.S. drilling activity. But since 2012 average costs have fallen partly due to more efficient technology. 

The M&A trend in Marcellus should continue through 2017, as there are remaining energy assets still ripe for targeting that took a hit during the energy market slump. For example, Stone Energy Corp. in February completed its reorganization and exited Chapter 11 bankruptcy proceedings, eliminating $1.2 billion of debt with a $527 million asset sale to EQT Corp.

Furthermore, President Donald Trump has loosened regulation on E&Ps, thus making such plays more lucrative. In fact, in anticipation of his energy policies, the bulk of 2016 transactions took place in the fourth quarter of 2016. Now as Trump held to his word, transaction flow continues 

Recently, the energy investment firm Kalnin Ventures LLC agreed to acquire more nonoperated Marcellus shale interests valued at $16 million on behalf of Banpu pcl., Thailand’s largest coal producer. Kalnin paid Range Resources $112 million and Chief Oil and Gas LLC $63 million last year for nonoperated interests there.

Cabot Oil & Gas Corp. has many infrastructure projects slated to come online in 2018. It announced that 67 percent of its budget would be spent on additional activity in the Marcellus with the rest going toward the Eagle Ford. In addition to E&P deals, there have been a number of midstream and oilfield services transactions this year, including Mammoth’s acquisition of various services companies valued at $134 million.

As for U.S. natural gas prices, increased M&A means more efficiency, more output and thus lower prices. It's not just about the resource-rich Marcellus shale, but that which lies beneath it -- the Utica Shale -- an organic-rich shale located a few thousand feet below, widely known as a source of natural gas, gas liquids and crude oil estimated to contain about 38 trillion cubic feet of natural gas, about 940 million barrels of oil, and 208 million barrels of natural gas liquids, according to the U.S. Geological Survey.

And from an international standpoint, Qatar has just lifted a 2005 self-imposed moratorium on developing the North Field in its efforts to capture more market share. Since 2005 Qatar was studying the effects of production in North Field which represents the majority of the nation’s 872 Tcf of natural gas reserves.