By Peter Gorman, Fort Worth Weekly, March 13, 2013
This article, from the Fort Worth Weekly, is an excellent piece and highlights the need before the United States launches into a gas export policy, to question what its implictions will be for American natural gas users. As the article points out, shale gas supplies appear to be much smaller than predicted, shale gas production is diving faster than projected, and the Enron type drilling boom that produced today’s natural gas glut is already dialing significantly back.
The exporting of the gas has many implications as many of the companies are planning on exporting to get higher prices as the dommestic supply shrinks. Although we can expect that the natural gas produced from oil shale fracking may pick up some of the slack, especially if scarcity makes it economic to collect and transport, rather than flare as is the current practice, if these facts are right, they should definitely be in a broad programmatic analysis of gas exporting before it is allowed to take place.
* * * * *
The early days of the shale gas boom around Fort Worth were heady ones. Chesapeake tossed money around as if it were limitless. Need a new museum of science and history? They helped cover it. A sponsor for the annual Thanksgiving parade? Done. Chesapeake hired actor Tommy Lee Jones to plug the benefits of natural gas with tag lines like “Let’s get behind the Barnett Shale” and “It’s here for good.” The industry group, Natural Gas Alliance, claimed the gas was going to flow for 100 years.
But is it? Two new and significant papers related to the finances of gas drilling and natural gas suggest the natural gas boom will not be here for anything like that long. The vast reserves touted by Chesapeake and every other natural gas company, and echoed by state and federal government agencies, have turned out to have been either mostly hype or so inaccessible that they don’t count for practical purposes. In just a few years, the boom has nearly gone bust, and it is beginning to drag a lot of communities and investors down with it.
Why? First, according to the authors of the reports, because the reserves simply are not there. And secondly, because a push to extract as much gas as possible from each field as quickly as possible has produced a glut on the market, which has caused natural gas drilling to be unprofitable in all but the very best areas of the best shale fields.
The drop in price, however, encouraged a lot of industries, including power companies, to retrofit their plants for natural gas rather than coal or oil. And without an abundant supply of gas over the long haul, that may prove very costly for consumers once the surplus of cheap gas is gone. Add to that a new wrinkle that not many people saw coming — the exportation of natural gas to countries willing to pay a premium for it — and the cost of natural gas in the United States could increase tremendously in the next five to 10 years.
In a paper published in February, Deborah Rogers, a former member of a Federal Reserve Bank of Dallas’ advisory council, described how the early years of the shale boom led gas drillers to borrow wildly so that they could get wells in before their leases expired. That caused an excess of natural gas, which dropped the prices to record lows.
And then the sky really fell in: The wells, especially in “sweet spots” like the Fort Worth section of the Barnett Shale, saw declines in production that no one could have imagined.
But the banks that had lent all that money to the energy companies needed their loans repaid, so energy companies had to keep drilling new wells to maintain production volumes. It looked good on paper and kept stock prices at reasonable levels for a few years, but with a couple of exceptions, nearly all of the gas companies have seen their stocks nosedive in the last year.
In the second paper, also published in February, geologist David Hughes, who worked for the Canadian government for 32 years, breaks down how quickly the major shale plays in the United States are being depleted. Hughes draws the conclusion that many, if not most, shale gas wells in this country will run dry in 10 years or less –– leaving a lot of investors holding worthless stock.
It’s an ugly picture –– for drillers, investors, banks, and all the industries that are retooling to use cheap gas that may not be there.
“I think the big winners in the game have already bailed, and a lot of people down the food chain are going to get burned in a few years,” Hughes told Fort Worth Weekly.
Wilson: “The drillers are not even looking at the gas as worth the price of putting in the infrastructure to capture and move it anymore.”
Hughes figures that shale drillers probably believed their own hype when they first married the hydraulic fracturing process (which uses high-pressure liquids to crack open shale rock and release the natural gas trapped inside) with horizontal drilling in 2002 in the Barnett Shale. “Initially, the drillers were comparing these to conventional gas wells,” he said, in which production drops quickly after the first year but then remains relatively steady, declining slowly over many years.
But, Hughes said, it couldn’t have taken long for the drillers to realize that their wells would reach terminal decline much more quickly. “The rocks in shale drilling are so impermeable that when we crack them, the gas is released much more quickly. So these wells may last 10 years or only six or seven before they have to shut them down. They’re so new that we have no history to show they will last more than 10 years.”
That didn’t keep the drillers from touting “40- to 50-year wells.”
It makes business sense that if you are trying to get people to invest in your company, you use the most optimistic estimates and claim the wells are going to last decades — “but nobody knows that,” said Hughes, “and looking at the rate of decline in production, well, they’re not going to last very long at all.”
The decline Hughes is talking about is steep. In the shale plays that produce nearly 90 percent of all shale gas in the United States — the Haynesville Shale in East Texas and Northern Louisiana, the Barnett Shale in Tarrant and several surrounding counties, the Marcellus Shale, which stretches from Eastern Ohio through Pennsylvania and south to West Virginia, and the considerably smaller Fayetteville, Eagle Ford, and Woodford plays — the decline in production averages more than 85 percent in the first five years.
When the Haynesville Shale, discovered by Chesapeake founder Aubrey McClendon, began to produce in 2008, gas companies flocked to buy leases and drill. By 2010 there were 180 drilling rigs working the play, and by 2012 more than 2,500 wells were producing.
But optimism turned to pessimism quickly: The production from the wells dropped 68 percent by the end of the first year, and by the end of four years, the average well was producing at less than five percent of its initial level.
“What you have to remember when looking at a shale play is that drillers head for the sweet spots first, the places with the most accessible quantities of gas,” Hughes said. “When the first few wells come in, a leasing boom follows. But the majority of the wells drilled are not going to be in the sweet spots — maybe only 15 percent will be. So when we look at the drop in the Haynesville play, what we’re seeing is that if the sweet spots are drying up, drillers wind up going after less productive areas in the play. But with the cost of each new well in the Haynesville at about $9 million — and that doesn’t include the leasing rights or costs of pipelines and so forth — and the price of gas at $3.30 per thousand cubic feet, who in their right mind is going to keep drilling?”
He pointed out that the number of drilling rigs active in the Haynesville has dropped from a peak of 180 in 2010 to 20 this year. “In the life cycle of a gas field, the Haynesville, at four years old, is already in late middle age,” he said.
In the Barnett Shale, where the average drop in production is about 30 percent each year, Hughes said, “You need to drill 1,500 new wells every year, each of which has the same average first-year production of a 2011 well, to simply keep [total] production flat.”
And that’s not happening. Devon Energy, the largest developer of natural gas in the country and, along with Chesapeake, the largest developer of the Barnett Shale, has reduced its rig count in the Barnett Shale to just six this year, according to spokesperson Chip Minty.
Julie Wilson, Chesapeake’s vice-president of urban development, said the company currently has only two rigs in the Barnett Shale.
So why did the companies keep drilling those wells, continuing the overproduction that meant they were selling their precious reserves at bargain-basement prices?
“It started with the land leases,” Hughes said. “Those leases have to be drilled in three to five years, or you’ve lost your investment.”
Rogers, the former investment banker, is currently a member of the Board of Earthworks/Oil and Gas Accountability Project. She started a goat farm in 2003 near Ridgmar Mall and became an activist on gas issues in 2009, when some of her goats died after being exposed to hazardous fumes from a nearby drilling operation.
“The way it worked is this,” she said. “In the beginning, the industry believed their own public relations. They really did think their wells would produce for decades. Chesapeake’s CEO McClendon estimated that the reserves of shale oil and gas were larger than ‘two Saudi Arabias’ at one point.”
Unfortunately, the wells didn’t perform as expected, “and the gas companies quickly learned that refracking the wells didn’t work and was just a very expensive exercise,” she said.
But the companies doing the drilling had committed millions of dollars to leasing acreage in the various shale plays and could not simply abandon that investment by letting those leases expire. Nor could they hold back on drilling even when the price of gas began to fall, Rogers said, because of the debts they carried.
“They had to keep drilling even though it didn’t appear to make economic sense, because they didn’t have any cash on their balance sheets, and they had tons of debt from all that leasing and the early drilling they’d done,” she said. “So continuing to drill — despite a growing glut that was dropping the bottom out of gas prices — was the only way they could make their debt service. That’s what we call the ‘drilling treadmill.’ They can’t get off.”
With prices so low, wouldn’t it make sense for companies to drill to maintain leases but not put their product on the market until prices rose? “They might want to wait,” Hughes said, “but they can’t hold back because of their debt structure. Wall Street investors are not known for taking a long look at things, even if the long look would show them what’s in their best interests. If they see production falling, the stock price will get hit.”
While the gas companies were scrambling to service their debt and keep their companies afloat, their investors and their investment bankers came up with an idea to make a fortune for themselves. The declining gas prices “opened the door for significant … deals worth billions of dollars … for the investment banks,” Rogers wrote. Wall Street began making deals to “spin assets of troubled shale companies off to larger players in the industry.”
Those included bundling of leased properties and selling off non-productive areas in shale plays. “Leases were bundled and flipped on unproved shale fields the same way as mortgage-backed securities had been sold on questionable … mortgage assets,” Rogers said.
“Investment banks used to help their clients,” she said. “That changed in the mid-1980s. They became predatory. They make money on the way up or the way down, it doesn’t make any difference to them.”
The banks made money on the loans they made to the gas companies, she said, and then when the fields didn’t produce as originally thought, the banks “realized that these companies were highly leveraged, and they kept the pressure on them through production targets. The rest is simple math: You could extrapolate that you would have a significant glut and that the prices would drop.”
Then the bankers turned to the major energy companies, both domestic and foreign, companies that Rogers said wanted nothing to do with shale at that point, and told them they could “pick up these assets for pennies on a dollar.”
So began a feeding frenzy of mergers, lease acquisitions, the outright sale of assets, and — in the case of XTO Energy — the acquisition of the entire company by ExxonMobil. The frenzy accounted for more than $46 billion in deals in 2011 alone, becoming the “largest profit centers for some Wall Street investment banks,” Rogers said.
The problem was that within 12 to 18 months, “the majority of these deals went south on the new owners,” Rogers said. “They’ve had billions of dollars of write-offs, and that translates into shareholder destruction. You’ve bought assets, but they’re no good anymore. And these numbers are huge, and they’re still growing.”
She pointed to two recent examples: Quicksilver Resources has had $2 billion of asset write-downs — writing down the value of assets — in the last six months. And Chesapeake sold its Fayetteville shale assets to the Australian mining giant BHP Billiton LTD.
At the time of that sale, Billiton boasted that it had more than doubled its U.S. oil and gas reserves, claiming it had added 10 trillion cubic feet of gas through the acquisition. Billiton paid Chesapeake $4.75 billion in cash in the February 2011 deal, but a year and a half later, they had to write down more than half of that investment. “The reserves are just not there,” Rogers said.
The losses hit everyone: Devon took $2 billion in losses in 2012; Chesapeake lost $3 billion in write-offs last year. “And the problem is that those write-downs, those losses, have an impact in the real world,” Rogers said. “The New York state pension fund was one of the largest owners of Chesapeake stock, and they have gotten creamed. This is reaching down into people’s retirement plans.”
Long before the massive merger and acquisition frenzy and the huge write-offs and write-downs began, some gas companies began to look at tight oil, or shale oil, for financial relief. Those are shale gas plays where there is a high volume of good quality oil that comes up with the natural gas. Two shale gas fields, the Bakken in North Dakota and Montana, and the Eagle Ford in Southeast Texas, produce about 80 percent of all the tight oil in the United States.
The method of extracting the oil with the gas is the same horizontal fracking used in natural gas drilling, but producers claim that because they’re really after the oil, the gas they get is free. But not everyone agrees with that assessment.
Sharon Wilson, Texas’ Oil & Gas Accountability Project representative and long-time activist against urban drilling, recently returned from a trip to the Eagle Ford play. “The drillers are not even looking at the gas as worth the price of putting in the infrastructure to capture and move it anymore” she said. “They’re capturing the oil that’s in the wet gas field and just letting the poisonous gas out into the atmosphere. When you look at the wells, the compressor stations, the processing facilities with an infrared FLIR camera that allows you to see gas in the air — well, it’s simply exploding out into the air.”
In the Bakken field, once considered the new Barnett Shale, Rogers said no one has even been willing to invest in a pipeline to move the oil and gas because “they see the handwriting on the wall. The reserves are declining too fast to warrant the $1.8 billion it would take to put a pipeline in place. So they’re shipping their product overland by train at triple the price. That tells you a lot about how fast those fields are declining.”
Mark Haggerty, an economist with Headwaters Economics, a nonpartisan, nonprofit economic research group, studied the Bakken. “About one-third of all the gas there is just being flared off,” he said. “It’s just not what they’re after.”
Between the Eagle Ford and the Bakken, it’s estimated that five billion barrels of good oil will be produced before the wells either go dry or are no longer economically feasible. According to Hughes, that’s about a 10-month supply of oil for the United States — not exactly a game changer.
At first, Haggerty said, gas companies estimated that once the field was drilled out, “it would produce 3.5 million barrels of oil a day. The reality is that it will probably only reach one million barrels daily in the next two years, and then it will start dropping off.”
For Haggerty, the dropoff will not only affect the bottom lines of the companies invested in tight oil and shale gas but also the communities from which those resources are extracted.
“We’ve done a lot of work looking at tax revenues versus the costs to the community,” he said. “And the real issue is: How does a community cope with what happens after the boom goes bust? You want the drilling for the tax revenue and royalties and jobs it creates. But at some point the impacts generated by the industry — the industrial and social impacts — simply outstrip the benefits of drilling. And for some communities, in the long run, they can wind up worse than they might have been if there had been no drilling at all.”
There is one way for the gas companies to get off their drilling treadmill. That would be exportation. In Japan, China, and Korea, a thousand cubic feet of natural gas goes for about $18 to $20 compared to just over $3.30 here in the United States. If companies like Chesapeake and Devon could liquefy their gas and ship it overseas, even at an estimated production and shipping cost of $9 per thousand cubic feet, they could do well, even with declining fields.
There are problems with liquefied natural gas (LGN) exportation, however. The United States currently has eight locations set up for receiving LNG from the Middle East but none set up for exporting it. Building the necessary terminals to convert natural gas to LNG would cost billions of dollars. And big industry, from companies like Monsanto to electricity providers that rely on natural gas to power their plants, are fighting tooth and nail against the export of natural gas, which would immediately eliminate the glut and steeply increase the cost of natural gas domestically.
(One of the reasons that TransCanada is so intent on bringing its tar sands down through the United States to the international free-trade port at Port Arthur is that the tar sands can be relatively inexpensively refined in Houston with cheap natural gas. If the price of natural gas goes up, a lot of expected tar sands profit goes out the window.)
Nonetheless, in October 2011, according to Rogers, the Department of Energy granted the first shale gas export permit, to Cheniere Energy, a Houston-based energy company that owns the LNG terminal in Sabine, La. By November 2012, Rogers said, the number of LNG export permits had reached 18 and represented a commitment of “60 percent of current U.S. consumption.” Such exports are expected to begin by late 2014 or early 2015.
If natural gas exports gear up, there would be a fairly quick and hard impact on consumers of natural gas in the United States. That is not a problem for the gas companies.
“Oil and gas companies are in business to extract hydrocarbons as cheaply and efficiently as possible and get them to the customer who will pay the highest price,” Rogers wrote. “Platform rhetoric about energy independence is nonsense.”
Hughes sees that happening in the next three to five years. “Once the glut is used and the primary fields have aged and lost productivity, there will be a shortage,” he said. “And at that point the price of natural gas will skyrocket. And the consumer will be the one paying for that as companies pass along the increased cost.”
Of course if the price of natural gas skyrockets, even peripheral shale gas fields and older fields — particularly those where the infrastructure is already in place, like the Haynesville, the Marcellus, and the Barnett — will be worth drilling again.
“What we’re looking at is a classic consumer squeeze,” Rogers said. “And if it’s not pretty now, just wait a few years.”