Tight oil’s impact on global gas markets
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Cheap Henry Hub gas, more competitive US LNG
The intensifying drilling up of the Permian Basin in Texas isn’t just delivering rapid growth in tight oil. There are huge volumes of gas too, the effects of which are rippling out into the US market and may have big implications for global gas prices too. On a visit to Houston last week I caught up with Kristy Kramer, Head of North America Gas research.
So Kristy, how important is Permian gas? Well Simon, there’s been a steady supply for decades, but the basin’s emergence as the pre-eminent tight oil play since 2010 has thrust gas into the limelight. Gas production was less than 4 Bcfd early this decade, about 6% of total US L48 output.
Oil drilling then took off. It’s about 7 Bcfd now, and will climb to 13 Bcfd by the mid-2020s with upside risk to 16-17 Bcfd. That would make the Permian 2nd in the shale rankings behind the Marcellus in the Northeast, a clear leader at 33 Bcfd, and these two will make up over 40% of US supply.
Are the economics of Permian gas compelling? Yes – it’s nearly all associated gas, and the cost to produce is close to zero.
Operators are targeting low-cost liquids, drilling wells typically with NPV15 breakevens well below US$50/bbl. The gas is a by-product. But as existing infrastructure reaches capacity, the primary challenge and cost is pipeline capacity to get the gas to market. The gas has to be produced with the tight oil; so operators will pay pretty much what they have to, to ensure profitable oil wells aren’t shut-in.
Higher-cost producers in other plays are being squeezed out, even though type curves are improving and costs falling. The Haynesville on the Gulf Coast has a huge resource, and as recently as 2015 we had expected production to follow a growth trajectory much as we see for the Permian now. There’s been a lot of drilling activity there in 2017 driven by private equity-backed players.
But while Haynesville costs are lower now, it’s not competitive in the longer term and will be squeezed out by cheaper Northeast and Permian supplies. The Marcellus is still growing, with new pipelines improving access and driving consolidation. EQT’s US$8.1 bn acquisition of Rice Energy this summer shored up its position in the SW Marcellus, lowered costs and ensures access to market. Expect more deals like this.
Is the increased supply reflected in price? It’s yet to happen, but it will.
Funnily enough, Henry Hub will be higher this year. There’s been very modest supply growth because of low prices over the last two years and a lack of pipeline exit capacity from the Northeast. Our forecast for 2017 is US$3.12/mmbtu, up 27% on last year. But that will change – as Permian and other low-cost supply builds, prices will dip toward US$2.50/mmbtu (real) and could stay there for some years.
Will domestic demand grow quickly enough to tighten the market?
Unlikely. Domestic demand is buoyant, and we expect growth of almost 10 Bcfd by 2020, mainly from the power sector. Sustained low prices through the next few years might add to that. But the dry gas cost curve is flat as a pancake and up to 15 Bcfd of new supply can be brought on stream within 12 months at US$3/Mcf or below. If the Permian does deliver the upside case of 16-17 Bcfd, there’s not much of an opportunity for dry gas.
And what about additional LNG exports?
That could help commercialise more gas, but only at the edges. Cheaper Henry Hub gas should lead to higher capacity utilisation on sanctioned LNG projects in the next few years. It will also push the many proposed new US LNG projects a little lower down the cost curve.
But these face multiple challenges to attract finance – an oversupplied global LNG market for some years, low oil and LNG prices, and fierce competition from overseas projects also trying to reduce costs. Creative commercial thinking will be needed if a second wave of US LNG projects is to get off the ground and offer a bigger outlet for US gas.