If you ask the CEO of Apache Corp., his company made in 2016 the kind of once-in-a-lifetime find that every oil driller dreams of: a massive oil and gas field that no other company noticed, where thousands of wells could be drilled and fracked to produce massive amounts of fossil fuels — and, in theory, profits.
Indeed, Apache expects a staggering amount of oil and gas can be found in this stretch of West Texas desert: 3 billion barrels of oil; 75 trillion cubic feet of natural gas; and even more natural gas liquids like ethane and propane, which feed plastics production. And it all sits on the outer margins of the famously prolific Permian Basin, where in 2017, one out of every three barrels of shale oil in America was pumped.
Alpine High, as the company named its discovery, was in a little-drilled area near Pecos, Texas, right on the outskirts of the Permian, on land ignored by other drillers who assumed there would be little potential for big oil finds letting Apache buy up leases for a fraction of the price of nearby land.
“We are incredibly excited about the Alpine High play,” John Christmann, Apache CEO, said at the time, “and its large inventory of repeatable, high-value drilling opportunities.”
But Apache’s big oilfield dreams risk doing irreversible harm to an irreplaceable place — and, some financial analysts warn, with no clear promise of big profits. Already, there are signs the wells may not live up to Apache’s early hopes and pressure has been growing from Wall Street to stop pouring money into huge infrastructure projects based on risky assumptions.
Nonetheless, Apache seems to still be dreaming big, pressing forward with plans to drill up to 5,000 wells, each with its own toxic wastewater, gas flares, and air pollution, all in the middle of one of the most ecologically sensitive places in West Texas.
The Manufacturing Model
Part of what sets Alpine High apart is Apache’s belief that the shale there is uniformly loaded with fossil fuels — or as Christmann put it in October, Alpine High includes multiple layers of underground rock that are “consistent, predictable, and contiguous” and “saturated with hydrocarbons.”
“The difference is this was laid out in a very quiet, tranquil marine environment,” he told attendees at the DUG Executive conference in Houston last month. “Sea level didn’t move much. It was just gradually rising and falling. It sets up an environment where you can do large-scale deposition [of fossil fuel] that’s pretty uniform,” he said.
But shale drillers have long been famous for predicting that all their wells in an area will be uniformly huge — and then having to admit that in fact, the rock has “sweet spots” that are smaller than expected. Early on, shale boosters claimed that fracking could replace the hit-or-miss gamble of wildcatters with a “manufacturing model” of oil drilling, methodically shattering oil and gas free from the dense shale where it was predictably trapped.
But it turns out that just like the best conventional oil and gas wells cluster together in sweet spots, shale wells do too.
That’s the warning that another famous shale executive, Mark Papa, has been preaching at several oil and gas conferences lately. Papa, who founded EOG Resources, one of the largest independent oil and gas companies in the US, made his name as a pioneer of the fracking industry. But these days, as CEO of Centennial Resource Development, he has soured on the prospects for shale profits and productivity, arguing at the CERAWeek conference in Houston in March that while the shale oil industry has built a reputation as a huge and disruptive new supplier of oil, especially after many shale drillers managed to survive a price war with OPEC, “[t]he impression of US shale as the big bad wolf is perhaps a bit overstated.”
He’s been spreading that message widely.
“Shale is like any other rock — the quality varies,” Papa’s November presentation, given at the Bank of America Merrill Lynch Global Energy Conference, says.
Papa estimated that a stunning 70 percent of the “Tier 1” acreage in some parts of Texas has already been drilled, leaving mostly “Tier 2” (or worse) wells left to be drilled. “There’s a steep drop-off in oil output/well between Tier 1 and Tier 2 geologic quality,” his presentation adds.
Apache spokesperson Castlen Kennedy told DeSmog that it was too early to determine how many sweet spots Alpine High might have, but that the company recognizes that “there are sweet spots in all plays, Alpine High included.” She added that the company also sought to highlight the point that Alpine High targets five layers of rock formations, three of which are thicker and more consistent than the layers other drillers are also targeting in the Permian. In 2017, its first full year, Apache drilled 45 wells across Alpine High’s 366,000 acres, the company’s SEC filing shows, including four wells that the company did not categorize as successful.
The issue of sweet spots raises broad concerns for the shale industry. A Massachusetts Institute of Technology (MIT) study last year found that government energy analysts made a crucial mistake in their yearly forecast, the Annual Energy Outlook. The government analysts assumed that shale wells were getting more productive because drilling industry technological innovations have allowed fracking to free up more of the oil and gas trapped in shale. But in fact, the MIT study found, the plunge in oil prices forced companies to find and drill their very best acreage first.
If accurate, their warning bodes poorly for the shale industry, because it means that in coming years, per-well productivity will drop as sweet spots run out, instead of continuing to rise as technology gets better.
Or, as Papa’s presentation concluded, “technology improvements can’t cure bad rock.”
That’s not for lack of trying. The desert atop the Permian basin is pocked with tens of thousands of oil wells and pump jacks, densely arrayed across the otherwise open plains.
By contrast, Alpine High’s 307,000 acres stretch under relatively untouched expanses of Texas wild country, where wild boar-like javelinas dash through the underbrush beneath some of the darkest night skies in the US
So many stars can be seen in this part of Texas that the Milky Way appears like a cloud and the view of the universe is so clear at night that at the McDonald Observatory, researchers have chalked up a long list of firsts, including discovering that one of Saturn’s moons has an atmosphere, finding the first known planet orbiting two suns, and spotting the most powerful supernova ever seen.
Alpine High also lies below Balmorhea State Park, where a breathtaking oasis is formed by natural springs that not only supply the world’s largest spring-fed swimming pool, but have also created a “cienega,” or a wetland ecosystem in the middle of the desert. In Balmorhea, over 150,000 visitors a year swim alongside schools of multiple species of endangered fish and SCUBA divers test some of the deepest underwater caves in the country.
All of this can be found amid the arid West Texas desert, a spot so remote that infamous American bankrobber John Dillinger is rumored to have hidden out from the law here in the 1930s.
Locals fear that the delicate springs could be disrupted by fracking, though Apache has promised to take protective steps such as not drilling right underneath the park.
However, Apache’s neighbors don’t have to look far to see the other cumulative impacts of oil and gas activities. Balmorhea is just an hour drive west of Wink, Texas, home to the “Wink Sinks,” two giant sinkholes that drew the attention of researchers at Southern Methodist University. It turns out that the ground in at least 4,000 square miles of Texas has been heaving and sinking, sometimes over 15 inches a year, and parts of the region are at risk of sudden collapses, the researchers warned when they published their findings in March.
“This region of Texas has been punctured like a pin cushion with oil wells and injection wells since the 1940s,” said study co-author and research scientist Jin-Woo Kim, “and our findings associate that activity with ground movement.”
Some of the gas from Alpine High will travel through the newly built Trans Pecos pipeline near Marfa, Texas, where the “Marfa lights” are beloved by UFO enthusiasts and other fans of oddities. Among the explanations locals offer for the zig-zagging lights that have been filmed zipping across Marfa’s horizons are not only UFOs or secret military tests, but also unique atmospheric conditions that might cause the light to play tricks on the eye — conditions that could be disrupted by air pollution from pipeline leaks, drilling, and fracking activity.
And what happens to the air in the Texas desert affects all of us, at least where powerful greenhouse gases such as methane are concerned. The environmental nonprofit Earthworks recently took high-tech infrared cameras out to Alpine High, recording a massive cloud of fumes, invisible to the naked eye, which rolled across the desert from a gas processing pad in Balmorhea.
Kennedy, the Apache spokesperson, said that FLIR cameras don’t show what chemicals are in “potential detections” nor the volumes emitted, and said that the facility is “in compliance with emissions standards” set by the state of Texas. Earthworks has filed a complaint to those regulators, not yet resolved.
“These videos prove they’ve broken their promise” to protect the local environment, Earthworks organizer Sharon Wilson said in a statement. “In doing so, Apache threatens the community’s health, the sky’s clarity, and the region’s economic engines, not to mention everyone’s climate.”
Devil in the Details
Alpine High contains over 75 trillion cubic feet of gas, plus 3 billion barrels of oil, Apache said when it first announced its find. Based on those numbers, oil should be about 16 to 20 percent of the total oil and gas mix coming from Alpine High (using common industry assumptions for calculating gas as a barrel of oil equivalent). But so far Alpine High wells have proven to be filled with more natural gas and natural gas liquids such as propane than Apache might have hoped.
Oil is much more highly prized by investors. While the price of US natural gas has plunged since 2008 and stayed low, the price of oil hasn’t fallen as dramatically and it’s currently back on the upswing. Oil can be refined into gasoline, while natural gas is primarily used by utilities at gas-fired power plants and by consumers to heat homes.
“The weighted average typical Alpine High wet gas well is estimated to produce 13.3 [billion cubic feet equivalent] of hydrocarbons, of which 6 percent is oil,” Tim Sullivan, Apache’s executive vice president, explained in an October update. He added that Apache now expects to be able to pump 455 million barrels of oil and natural gas liquids from the entire region, by drilling 5,000 locations in what has long been wilderness.
Overall, he said, Apache expects its liquids-rich wells to eventually wring about 13.4 percent of the 3 billion barrels of oil it said it found in Alpine High from below the desert sands. Some early analysts had expected that Apache could profitably produce a third or more of those 3 billion barrels when Alpine High was first announced.
That 13.4 percent is still a significant amount of oil — enough to supply the entire US for about 23 days, at 2016 consumption rates. But investors didn’t like what they heard, with Apache’s share prices sliding sharply in October. Analysts from Woods Mackenzie chalked that slump up to skepticism over Alpine High, calling the sell-off “a bit of de-risking.”
It was the prospect of oil and liquids, not dry natural gas, that had drawn Apache to Alpine High from the start. “We were able to confirm that we were in an oil window,” Christmann explained in a November 2016 interview with the trade publication Oil and Gas Investor. “Obviously, we’re going to focus on the oil zones and the wet gas play,” he added.
But Apache’s first wells did better than some that were drilled later. Investors were disappointed that Alpine High’s well results in early 2017 were “weaker than previous results,” as a note from investment bankers at Piper Jaffray put it. “Bottom line, we’re skeptical,” Hassan Eltorie, IHS Markit analyst, told The Houston Chronicle last year when the company’s wells showed less oil than hoped. “And this is not an encouraging sign.”
Alpine High’s profitability is also highly reliant on new pipeline construction plans going smoothly. Pipeline projects are “a critical piece to the story for the near-term,” Christmann told investors during Apache’s most recent investor call.
In December, Kinder Morgan announced it would move forward with a $1.7 billion 430-mile natural gas pipeline after signing on Apache as its anchor customer. The Gulf Coast Express pipeline will run from Waha, Texas (about an hour’s drive from Balmorhea) to just outside Corpus Christi, on the coast of the Gulf of Mexico. The Trans Pecos pipeline, which was completed a year ago, had sparked an encampment, regulatory challenges, and over a dozen direct action protests.
Apache’s Alpine High plans rely on building much more infrastructure to carry their gas to market. “I cannot overstate the strategic importance of the midstream [pipeline] solution to Alpine High,” Christmann added.
But all that infrastructure costs money, and many analysts pointed to Apache’s expensive buildout as driving the stock slump in late 2017. Oil and gas investors are generally growing weary of funding more costly projects when the risks are so large. Because Apache arrived late to the Permian rush, it’s behind the curve on spending, with The Wall Street Journal citing Apache as an example of a company where a transition to profits from shale wells “could take time.”
And that’s not the message investors want to hear right now. “Most US shale producers have failed for years to turn a profit with the increased output, frustrating their financial backers,” CNBC reported in February.
That record just might be starting to catch up with the industry on Wall Street.
“Last year, it was drill, baby, drill,” Hess Corp. CEO John Hess said at CERAWeek, an oil and gas industry conference. “This year, it’s show me the money.”