Sumitomo’s Loss Shows Shale Isn’t Booming for EverybodyAsjylyn Loder
Land in the Permian Basin, the busiest shale patch in the U.S. oil boom, is worth either $1,000 an acre or 50 times more, depending.
On Sept. 29, Calgary-based driller Encana Corp. announced plans to buy a company that owns a West Texas prospect for $7.1 billion, or about $50,000 an acre. One day later, Tokyo-based Sumitomo Corp. estimated its land in the same region was worth a fraction of that price when it took a $1.55 billion writedown on its investment.
The disparity shows how fickle the oil business can be in the Permian, the source of more crude output than California and North Dakota combined. Despite assurances from some shale companies of assembly-line predictability, promising acreage can turn out to be a golden opportunity or expensive goat pasture. Falling oil prices, like the 12 percent drop witnessed in the past three weeks, make investments even more perilous for exploration-and-production companies such as Encana.
“They’re paying for the potential,” said Sameer Uplenchwar, a Calgary-based analyst with Global Hunter Securities LLC. “Based on what we see today, it’s a good deal. The only way it doesn’t pan out is if we assume oil prices go really low.”
He said oil at $60 a barrel could create problems for Encana. That’s still 27 percent away from the U.S. benchmark price, West Texas Intermediate, which has plunged 23 percent since June to $82.71 a barrel. Energy stocks have also declined. The SPDR S&P Oil & Gas Explorers and Producers exchange-traded fund fell 29 percent over the same period. Encana shares have risen 4.7 percent in the last year.
Sumitomo decided to sell the northern portion of its Permian holdings and will continue to develop some of its southern properties there, Koichi Takahata, managing executive officer of Sumitomo, said in a Sept. 29 briefing. The book value of the assets is about $200 million. That comes to about $1,000 an acre for its 30 percent share of about 650,000 acres.
“With the size of the losses, we’re going to take a very thorough look at the causes,” Hiroyuki Inohara, Sumitomo’s chief financial officer, said at the briefing.
Oklahoma City-based Devon Energy Corp., Sumitomo’s partner, doesn’t face “the same impairment challenges” because the cost of drilling was largely paid by Sumitomo, the company said in a Sept. 30 statement.
Encana will pay $58.50 a share to buy Athlon Energy Inc., a four-year-old Fort Worth, Texas-based driller backed by buyout firm Apollo Global Management LLC. Athlon was trading at $46.73 before the deal was announced. Athlon has about 140,000 acres in the eastern part of the Permian Basin, a 75,000 square-mile (194,000 square-kilometer) underground petroleum deposit that stretches into New Mexico. Athlon’s shares have increased 72 percent in the last year.
The bear market for oil changes the economics of the Encana deal. The purchase price equates to about $56 for every barrel of proved reserves Athlon reported to the U.S. Securities and Exchange Commission at the end of 2013. That’s about $27 a barrel less than today’s crude price. The gap was nearly $39 a barrel on the day the deal was announced.
William Butler, Athlon’s chief financial officer, didn’t return calls seeking comment.
After accounting for the value of Athlon’s existing wells, which produce about 28,000 barrels a day, the value of the land alone comes to about $29,000 an acre, according to a Sept. 30 report from Dave Meats, an analyst with Morningstar Inc. in Chicago. Other recent Permian deals went for $22,000 an acre to $25,000 an acre, he said.
“What we’re acquiring in the Permian is really the upside and the opportunity,” said Jay Averill, a spokesman for Encana.
Encana will spend $1 billion next year drilling in the Permian, and predicts that its output will reach as much as 250,000 barrels a day in five years, Averill said. The prospect will be profitable well below current commodity prices, he said.
Starting in 2010, funds managed by New York-based Apollo, which is headed by billionaire Leon Black, invested $362 million in Athlon. The funds have already taken $1.1 billion through shares sales and will get $1.48 billion in the sale to Encana, according to company filings. That works out to a gain of $2.22 billion, or more than 600 percent. Charles Zehren, an Apollo spokesman at Rubenstein Associates Inc., declined to comment.
Athlon has drilled only a handful of the more complex wells that characterize the shale boom, focusing instead on traditional vertical wells. Shale wells are drilled horizontally along layers of oil-soaked rock, which is then blasted with water, chemicals and sand to free hydrocarbons, a process known as hydraulic fracturing, or fracking. Horizontal drilling is more predictable than the traditional, straight-down search for pockets of trapped fuel. In a vast expanse of rock, there’s far less chance of a dry hole.
Horizontal wells produce more oil than traditional wells. They’re more expensive, too. Athlon’s horizontal wells cost as much as $8.5 million each with ultimate yields estimated at 625,000 to 880,000 barrels, company records show. The company’s vertical wells average $1.9 million apiece and are forecast to produce 140,000 to 236,000 barrels.
Athlon’s approach allowed the company to attract investors by using its cheaper, vertical wells to identify potential locations for horizontal drilling. When the company went public in August 2013, it had drilled 230 vertical wells and not a single horizontal, according to its prospectus.
Athlon started drilling horizontal wells in the last three months of 2013. Its annual report to the SEC said it had the equivalent of 127.3 million barrels in proved reserves at the end of last year, meaning it had “reasonable certainty” that amount would be produced from existing wells and those scheduled to be drilled within five years. Only 46.7 million barrels of those proved reserves were attributed to wells that have already been drilled.
None of those barrels were associated with its horizontal wells. That will change when the company reports end-of-2014 reserves to the SEC, Robert Reeves, Athlon’s president and chief executive officer, said in a Sept. 4 presentation at the Barclays CEO Energy & Power Conference in New York. Athlon’s 2014 acquisitions had already boosted reserves, he said. Using an estimate not governed by SEC reporting rules, Reeves told investors Athlon’s “resource base” was more than 1.4 billion barrels.
“And it continues to grow,” Reeves said at the conference.
It doubled in less than a month. When Encana announced the acquisition on Sept. 29, the Canadian driller counted “potential recoverable resource” of 3 billion barrels.
Encana’s higher estimate assumes wells can be placed closer together, said Averill, the Encana spokesman. If Encana is right, it’ll have paid less than $3 a barrel to acquire the acreage, he said.
“We’re very confident in our ability to realize that potential,” Averill said. “This is 140,000 acres that are virtually untapped by horizontal drilling.”
Whether the potential will materialize requires years of drilling and billions of dollars in investment. There are no guarantees. As Sumitomo learned, the potential can evaporate. In August 2012, the Japanese trading company bought a 30 percent stake in 650,000 acres from Devon. The company had pioneered horizontal drilling, which sparked the boom in energy production that pushed U.S. output to the most in 29 years. On its website and in its investor presentations, Devon describes its potential for “low-risk, repeatable drilling.”
Sumitomo’s joint venture with Devon covered a swath of the Midland Basin in the Permian’s eastern portion. Sumitomo paid $340 million in cash and agreed to foot the bill for most of Devon’s drilling costs up to $1.025 billion. At the time, Devon had drilled only a handful of horizontal wells in the area at a cost of as much as $6.5 million each, company records show.
Devon estimated that its share of the oil and natural gas in that acreage was the equivalent of 3 billion barrels of crude, according to company investor presentations. With Sumitomo’s stake at 30 percent, its potential was the equivalent of about 1.3 billion barrels. Both Sumitomo and Devon declined to comment on that estimate.
However promising it looked to Sumitomo in August 2012, Devon had yet to deliver. Devon’s estimate of 3 billion barrels of “resource potential” dwarfed the proved reserves of 200 million barrels it reported to the SEC under the regulator’s tighter rules. And the lower number included Devon’s interests in all of the Permian Basin, some of which didn’t involve Sumitomo.
In May 2013, eight months after Sumitomo’s investment, David Hager, Devon’s executive vice president of exploration and production, told investors at the UBS Global Oil & Gas Conference that a portion of the joint venture, an area called the Cline, had faults that made drilling difficult.
“The results that we’ve seen so far are very mixed, I would say,” Hager said.
Some wells pumped as much as 800 barrels a day in their first month, Hager said in a May 2013 earnings call. Others pumped less than 50 barrels a day, not enough for Sumitomo to cover its share of the investment in wells that cost $6 million each.
“As a responsible operator, Devon continually manages and evaluates its entire portfolio of assets to ensure optimal results,” Devon said in the Sept. 30 statement. John Porretto, a spokesman for Devon, declined to comment further.
Devon is having better luck on the western edge of the Permian in the Delaware Basin, and is steering most of its resources there, company records show. Sumitomo owns no share of that acreage.
“Even if the technology seems like it can do it, the geology turns out to be very complicated,” Takahata said at the Sept. 29 briefing. “A big issue now is how to be able to see beforehand what risks lie below ground.”
(An earlier version of this story corrected the WTI price in the fifth paragraph.)