Along the bottoms of the Mississippi River channel, the churn of sand and sediment can be constant, endlessly shifting and sweeping it along with the current. In his book Rising Tide, John M. Barry quotes civil engineer John Eads who witnessed this tumult firsthand after (purposefully) sinking himself to the bottom of the river and thereafter comparing the shifting sands to a “dense snowstorm.” This storm continues to drift along the floor of the Mississippi River even today, while just above the surface, great barges carrying even more sand are headed to oil and gas basins across America. However, the owners of the onboard material would be quick to protest that their product is not just sand. No, this sand strives for the perfect denseness, size, and consistent “sphericity” to serve as one of the most sought-after ingredients in oil and gas completion operations. This is frac sand.
The Red River Parish Port sits along a quiet stretch of the river in Hanna, Louisiana, roughly 60 miles due south of Shreveport on Highway 1. The Port near Hanna receives multiple barges every week, each carrying many tons of frac sand. Seeing this great influx, one may worry that Hanna risks disappearing beneath it all; however, as fast as the barges arrive, the sand is then transported away to staging areas or directly to oil and gas drilling sites. The port at Hanna is but one of a number of ports in Northwest Louisiana which have seen an increase in barge traffic related to frac sand as of late. The largest port in our region, the Port of Caddo-Bossier located in South Shreveport along the Red River, has seen especially significant gains recently. “The amounts of frac sand received at the Port by both barge and rail showed a significant increase over the last four months of 2016” says Eric England, the Executive Port Director at Caddo-Bossier, “And those levels have continued thus far into the first quarter of 2017.”
A very simplified description of frac sand’s role in oil and gas drilling is that it serves as part of a mixture which is pumped at extremely high pressures into unconventional formations such as the Haynesville shale. The mixture serves to fracture the rock in a targeted area downhole and the frac sand remains within the formation in order to prop the fractured channels open, allowing the production to flow into the well bore, or the actual hole that forms the well. Due to this role, frac sand is also referred to as “proppant.”
The shipping of frac sand into the Shreveport area is nothing new; however, this recent uptick in volume may tell us more about the changes in oil and gas well economics than it does about the actual number of wells being drilled. Currently, Northwest Louisiana is in the midst of a mild reawakening of drilling activity and the driving factors behind this resurgence could solidify the Haynesville shale as a perennial economic asset for our area.
The Haynesville’s Ramp Up:
We are nine years removed from the initial push to lease and drill the Haynesville shale in this area. Over that time, we have witnessed the frenzy of activity that accompanies the first few years of any oil and gas exploration prospect. However, the early drilling activity was as much a reflection of the oil companies’ contractual obligations to drill or lose their leases as it was about actual supply and demand economics.
The typical oil and gas leases with the mineral owner do not require the oil company to drill in most cases, but they do set out a limited window in which they may drill and produce the lease or lose their right to do so altogether. Customary lease terms allow the company about three years to take action, though some leases are longer and some are shorter. It is because of these time constraints that drilling activity in a prospective area balloons in the beginning as companies seek to lock their leases down into “held by production” status, meaning the lease will carry forward for as long as it continues in production.
In the Haynesville Shale, the leases’ use-it-or-lose-it ultimatum was even more pronounced than in most other areas due to extremely high amounts which were paid as up-front “bonus” money to acquire the lease rights. In essence, the companies were committed to a race against the clock to produce their Haynesville acreage quickly or they would be forced to write off truly staggering economic losses if and when those lease rights lapsed—so produce they did.
After the Gold Rush
By 2011 and 2012, the majority of the Haynesville leases were secure within producing “units”, such that all the leases within a 1-square-mile range (the most common dimension of a Haynesville shale unit) were in “held by production” status. Without contractual obligations requiring a higher rig count, we could now see what the Haynesville Shale looked like when laid bare before the market. This exposure to supply and demand unfortunately coincided with a plunge in natural gas prices. The price of gas fell from highs of over $10.00/mcf in 2008 to averages under $3.00/mcf in 2011—a splash of cold water in the faces of companies who had just invested a great deal in the play (shale formations) with the expectation that natural gas would remain a hot commodity. The price then continued declining, even falling below $2/mcf for a period in early 2012. These dismal prices upended the carefully-calculated business models of even the most sophisticated exploration companies. The rig count in the Haynesville reacted with a precipitous slide in 2011 and 2012.
It didn’t help the Haynesville’s economics that other shale plays throughout the country had just begun their own drilling frenzies to maintain new leases around this same time. Basins such as the Eagle Ford Shale in South Texas and the Marcellus and Utica shales in the Northeast U.S. all had large areas of lease acquisition too. As in the Haynesville, the operators in these varied regions each drilled heavily to maintain their acreage during early exploration. Not all of this activity was in pursuit of natural gas, but the continued drilling had the net effect of increasing natural gas supplies and providing a short-term ceiling on the price of the Haynesville’s showcase product.
In these dog days, any new drilling in the Haynesville was isolated to targeted areas where companies still needed to meet contractual obligations, or in those rarified areas where impressive production returns allowed the economics to work out even at depressed prices. Everywhere else, most companies reserved themselves to simply maintain their currently producing wells and temporarily shelved plans to further exploit the deep reserves of the Haynesville.
The Evolution: Longer Wells, Lower Costs, and Better Completions
In 2011, the typical horizontal well extended almost the length of a production unit, save for a 330-foot “setback” area near the unit boundaries in which the operators were not allowed to complete their wells. It was in this year however that the Louisiana Office of Conservation first authorized the drilling of cross-unit laterals, sometimes termed “CULs.” The CULs were important to allow the operator to not only drill through, but also produce the setback areas which were previously off limits. On average, production of a unit’s setback area would unlock about 80 acres or one-eighth of the unit, which was previously being left unproduced. Encana Oil and Gas (USA) and SWEPI, LP drilled the first CUL in the Haynesville shale later that year, and it would not be long before other operators would follow suit with their own CUL program. Shreveport-based independent landman Skip Peel has always monitored the regulatory filings in the Haynesville for his clients and found that the CUL’s popularity grew very quickly. “Today the cross-unit lateral has gained great popularity in the Haynesville, and represents a large number of the Haynesville drilling permits”, says Peel.
The total length of the CULs in the Haynesville has varied. Some operators have sought only to extend their new wells through the former setback area and then just into the adjacent unit to also produce its setback area. Other wells are drilled anywhere from a mile and half (producing a full unit and half of an adjacent unit), up to those producing two entire units and even beyond. Skip Peel says the current trend may be for the longer CULs, especially when a company’s drilling pattern permits it. “A number of operators are now able to push their lateral lengths to 10,000 feet and beyond in certain areas” says Peel.
In addition to allowing the operator to reach previously closed-off resources, CULs also created tremendous economies of scale. Robert Clarke, the Research Director, Lower 48, of the research and consulting group Wood Mackenzie agrees that opening an exploration play up to extended laterals provides any immediate benefit. “Many drillers will tell you that the cheapest foot you will drill is very likely your next one”, says Clarke. It also hasn’t hurt that costs for rigs and well completion services have dropped as the recent decline in oil prices left the service companies with extra capacity. Clay Lightfoot, Wood Mackenzie’s top Haynesville Analyst has studied the recent Haynesville economics, and suggests that “cheaper services along with longer laterals in some cases has allowed companies to drill twice the well for similar costs to their original wells in the Haynesville.”
The CUL advantage was even more apparent upon Chesapeake’s announcement last August of the initial results of its CA12&13-15-15 1H horizontal well in Caddo Parish. This well was drilled as a 10,000-foot lateral, essentially the length of two production units, with reported costs of around $9.8 million. The estimated ultimate recovery (EUR) of the CA 12&13 was stated as possibly reaching 22-24 billion cubic feet (BCF) of natural gas over the well’s life. For perspective, the average cost of a single Haynesville well in 2008 and 2009 was around $10 million, with even the most hopeful well’s EUR falling in the 8-9 BCF range.
Of course, you don’t get a 20+ BCF well just by drilling longer wells. On an August 4, 2016, earnings conference call, Chesapeake CEO Doug Lawler stated that the CA 12&13 used over “30 million pounds of sand” and announced a plan to test future wells at “50 million pounds of sand” during completion. On the call, Lawler coined a new catchword in the Haynesville as he explained Chesapeake’s ambitious new completion technology, calling it “proppant-geddon.”
Make no mistake, frac sand was big business even before the rally cry of “proppant-geddon.” The profit margin is such that mining companies within that industry have been quick to develop the sand’s source, process the product to the necessary specifications, then ship the sand thousands of miles to its sales point. I guess it is somewhat fascinating (if not humorous) that all of this commerce has been created by simply taking the ground from one place, moving it halfway across the country, where someone will then pay millions of dollars to shove it back into the earth. But it’s hard to argue with recent results, and currently the operators in the Haynesville shale have found sand to be a major component in unlocking value at lower commodity prices.
Enter Private Equity:
It is not complicated math: double the volume + similar well costs = higher returns. These higher returns have attracted the attention of a number of private equity groups who have begun purchasing positions from former Haynesville operators or by simply purchasing those companies outright. Two early examples include Vine Oil & Gas’s 2014 acquisition of SWEPI, LP’s lease holdings in the Haynesville, and then Geosouthern Haynesville’s 2015 purchase of Encana Oil & Gas’s Haynesville interests. Both Vine and Geosouthern are ultimately backed by private equity.
More recently, we have seen the private-equity fueled Covey Park Energy step in and make multiple purchases of Haynesville assets. The first of these was a March 2016 acquisition of a portion of EP Energy’s Haynesville holdings. Still hungry, Covey Park then acquired a sizable portion of Chesapeake Energy’s lease acreage in December 2016. With these two purchases, along with another purchase from EOG Resources in 2016, Covey Park has become the holder of one of the largest positions within the combined east Texas and Louisiana sides of the Haynesville Play. Covey Park Energy was formed with funding provided by Denham Capital, a private equity firm with a focus on energy related assets.
It is important to note that private equity-backed companies have a distinct business model which can differ in many ways from that of a traditional public producer. Robert Clarke with Wood Mackenzie finds that one main distinction is that “private equity sometimes places an emphasis on shorter-term investment time frames, rather than the patient approach that larger operating companies can showcase when their portfolio isn’t tied to just one asset.” However, a focus on the shorter term does promote more immediate exploration activity. Clarke suggests that “the influx of private players is a likely reason Haynesville activity accelerated throughout 2016.”
In April of this year, the United States Geological Survey (USGS) revised previous reports created by the agency that dramatically increased their estimates of potential recoverable natural gas in the Haynesville area. The report was quite a nod in our region’s direction as the Haynesville formation (including the associated Bossier formation) was deemed the largest continuous natural gas assessment ever performed by the USGS. The newer completion techniques and longer well laterals played a large role in the USGS revision, which sought to identify the amount of product actually recoverable through exploration – a constantly moving target as technology advances.
Prediction is very difficult, especially about the future. —Nils Bohr
The new completion technology resulting in increased recovery of natural gas is certainly hopeful for our region, but the gas from the Haynesville area is only as relevant as its own economics allow. Just as sand may be the bellwether of increased production, the increased production itself may be the canary in the coal mine for commodity prices. Exploration companies have shown they can turn on the spigot very quickly in an established play. Along with the higher volumes of the newer wells, it would seem the supply side may be poised to dampen any short term increases in the price for natural gas. Many experts have used the term “range bound” when describing commodity prices, meaning we are unlikely to see any sustained periodic spikes in natural gas prices like those in 2008 which drew the operators to the Haynesville. “The days of natural gas prices over $6/Mcf may be gone for good” says Skip Peel.
Of course, the demand side for natural gas has reacted to the lower prices. Natural gas is utilized as a component in a number of industrial operations along the Gulf Coast such as the manufacture of ethylene, a key ingredient in plastics. There have also been multiple liquefied natural gas (LNG) export facilities constructed along the Gulf Coast, one such being Cheniere Energy’s export facility at Sabine Pass near Lake Charles, Louisiana. Cheniere initiated its first exports of LNG in early 2016. Similar facilities for the export of LNG are in the works, one of which is the “Driftwood” facility being developed by Tellurian, Inc., which is also located near Lake Charles.
Although it is difficult to predict the future economic impact oil and gas exploration will have in our region, it appears more certain that the Haynesville shale will see continued development for years to come as it seeks to solidify itself as the premier natural gas play in America.