US gas galore
Returns have been more difficult to find than gas in the Marcellus and Utica shale plays. New pipelines opening up fresh markets and better wells could help improve things
The greatest gas growth story in the world over the past decade has come out of America's northeast with the development of the vast Marcellus, and more recently the Utica, shale plays. The Appalachian gasfields' explosive growth has driven the transformation of America from the world's largest gas buyer to being on the cusp of becoming a global gas powerhouse, overturning the domestic market, the international gas trade and energy geopolitics in the process.
The Appalachian gasfields weren't on the market's map at the start of this decade. But over the past seven years, production has risen more than ten-fold to record highs this winter of more than 27bn cubic feet a day. This is more than half total US shale-gas output, and more than one-third of all gas produced in the country. The Marcellus, which covers more than 95,000 square miles stretching from New York south into Kentucky, accounts for around 80% of this output. But the Utica, which is about a decade behind the Marcellus in development, is growing quickly.
That growth shows few signs of slowing, even with natural gas prices hovering around $3 per million cubic feet. Seven of Appalachia's largest gas producers plan to continue growth at a healthy double-digit clip in 2018 and 2019, according to data compiled by the investment bank Jefferies. Those producers, which account for more than half of output, plan to add 1.9bn cf/d of production in 2018 and 1.7bn cf/d in 2019, which would see Appalachian output cross 30bn cf/d before the end of the decade.
EQT Resources is leading the way on Appalachia growth. EQT, whose $6.7bn takeover of Rice Energy will make it America's largest natural gas producer, surpassing ExxonMobil, plans to add 1bn cf/d in the Marcellus and Utica by 2019 on its own. Cabot Oil & Gas, an early pioneer in the Marcellus, also plans to add as much as 1bn cf/d by the end of 2019, with annual growth of around 20%. Antero Resources, a Utica specialist, plans to add another 0.5bn cf/d over the next two years, expanding its production by 30%. Smaller drillers are struggling more with persistently lower natural gas prices, and will struggle to muster the capital to match these growth rates, but the bigger producers will be able to fuel growth for the foreseeable future.
The big question for investors is whether or not Appalachia's producers will finally be able to turn eye-watering growth rates into profits. The volume-over-value debate that has gripped the tight oil investment community will sound very familiar to shale-gas investors. Many shareholders argue the Appalachian producers have drilled themselves into a financial hole by continuing to pump record amounts of gas into a saturated low-priced market. Over the course of 2017, those top seven producers saw their shares fall on average by a third. Cabot managed a 14% gain, the only one of the companies to see a positive return. Southwestern Energy, Range Resources and Gulfport all saw their shares fall by more than 50%, far outstripping the roughly 7% decline in Henry Hub.
27bn cf/d—Appalachian shale gas production
Is there hope for a turnaround for the economics of drilling in the Appalachian? There are two strong arguments for why better days lie ahead for producers: new pipelines and better wells.
The first, and probably most important, is that at long last a wave of new pipelines are being built. That should alleviate a regional glut, which has undermined prices at northeast hubs. These have traded at steep discounts to Henry Hub for most of the past three years as pipeline capacity has failed to keep up with output growth. The discount has averaged around $1.50/m cf, meaning realised prices for Marcellus and Utica producers have rarely topped $2/m cf, and in times of relatively weak demand have fallen below $1/m cf.
That should change in 2018. In total, around 4bn cf/d of new pipeline capacity is expected to be added over this winter. The largest is the continued expansion of Energy Transfer's Rover Pipeline, with a combined 2.5bn cf/d of capacity coming from phases 1B and 2 of the line. Rover will give Appalachian producers access to the Midwest, and beyond, where they will be able to fetch higher prices than they have in the glutted northeast. TransCanada's 1.5bn cf/d Leach Xpress line is another vital new connection for northeast producers to markets outside the region. Analysts say these projects should close the gap between the northeast's hubs and elsewhere in 2018, if not eliminate the differentials altogether.
Drillers are also continuing to hone their craft, making Marcellus and Utica wells more economic. Like in the tight oil patch, Appalachian shale-gas producers are seeing benefits from drilling longer lateral wells and pumping more proppant into each one to create bigger fracks. This trend, in fact, has driven much of the recent deal-making activity in the region. Companies wanting to drill longer lateral wells in the Marcellus, two miles or more in many cases, have often run into the problem that their acreage simply isn't large enough and they're hemmed in. When EQT bought Rice, it said it was doing so in large part because Rice held a significant amount of acreage adjacent to EQT's, and buying it would allow the company to drill much longer and more profitable wells. That, EQT's executives said, gave it an advantage over other Marcellus drillers that couldn't stretch their wells to the same lengths.
EQT claims these longer wells, with a much higher fracking intensity, dramatically reduce unit costs and improve productivity. In a presentation to investors, the company says that at a $2.50/m cf gas price, the 12,000ft wells return 59%, compared to 37% for a 6,000ft well and 33% for a 5,500ft well. EQT says its average well length in 2018 will be 12,000ft plus, twice what it was a couple years ago.
Antero, too, has argued that its large holdings, allowing for longer lateral wells in the core of the Utica, set it apart from its competitors. "Antero holds over 30% of the long lateral inventory beyond 10,000ft, outpacing our closest peer by a wide margin," the company's chief executive Paul Rady told investors in November. "The ability to continue pushing the average lateral length of our locations has been a key factor in the capital savings we have achieved to-date and expect to achieve over the next several years." Putting a figure on the savings, Rady said the company could deliver the same level of production growth it outlined in January 2017 with $1.5bn less in capital spending, thanks to the new well designs.
Eclipse Resources is perhaps pushing the boundaries the farthest on lateral length. The company has put together huge blocks of acreage across the Marcellus and Utica, allowing it to drop some of the longest lateral wells ever drilled anywhere in the world. It has drilled lateral wells more than 18,000ft, nearly three and a half miles, and plans wells as long as 20,000ft. Many analysts assume producers will at some point see diminishing returns with these longer lateral wells, where the extra cost of drilling will start to negate the added productivity. But Eclipse claims its returns have only improved, the longer laterals they've drilled. Eclipse claims internal rates of return for 20,000ft laterals at its liquids-rich Utica acreage are 71%, compared to 54% for a 13,000ft lateral.
Some analysts warn that producers are getting ahead of themselves with optimism over the new wells. They argue that higher initial production rates, the amount of gas produced in the first 24 hours after a well is brought online, don't necessarily mean that the wells will ultimately produce more gas, the key metric for a well's productivity. Because most of the bigger wells have been in production for a year or less, the long-term data is limited. Others warn that the more intense drilling could be doing long-term damage to the productivity of the reservoirs. However, for now, producers are convinced that bigger wells are the way forward and will continue pushing the boundaries.
Much of the Appalachian drillers' financial health will, of course, hinge on the gas price. A major breakout looks unlikely. The market is so well supplied that even as a record-breaking freeze gripped much of the eastern seaboard in January, and gas demand hit new highs, the NYMEX benchmark price barely managed to break $3/m cf. The benchmark hasn't cracked $4/m cf since late 2014.
The good news, for producers, is that a slug of fresh demand is on the way from new liquefied natural gas export facilities. These will add nearly 7bn cf/d of export capacity, equal to close to 10% of existing demand, by the end of next year. Assuming the plants run at around 80% of capacity, that should add around 5.5bn cf/d of badly-needed new demand in just two years.
That isn't enough to lift prices significantly, but it should help put a floor under them and prevent the kind of collapses that have gutted Appalachian drillers' finances in recent years.