Permian gas seeks exits
The glut of associated gas production in the Permian Basin has led to a scramble to build new takeaway capacity, although significant relief will not come before 2021
The Permian is now the second-largest contributor to US shale gas production after the Appalachian Basin. However, the play’s growth is being driven by different dynamics, as the region’s unconventional operators are primarily targeting crude, with associated natural gas largely a by-product of the oil drilling taking place.
In contrast with dry gas plays where it is the primary target, gas in the Permian has often been treated as an afterthought—and even a nuisance. But, as infrastructure starts to catch up with production, opportunities are emerging to harness associated gas output to create additional value.
That Permian activity is driven far more by the economics of oil drilling than gas is best illustrated by the fact that gas spot prices at the Waha hub in Texas fell into negative territory on 41 instances between March and August 2019. At such points, drillers were paying to have their gas taken away, or it was simply being flared.
“Clearly price and availability of gas versus oil plays a significant role here,” says Ian Simm at advisory firm Gneiss Energy. “The intention has been to produce oil, which is why there has been such a shortage of gas infrastructure. This is not uncommon, but, considering the wastefulness and environmental issues caused by gas flaring, other oil plays globally have found better ways to utilise or monetise associated gas. Negative gas prices allude to this issue, but we are seeing the tide change here.”
The Permian’s gas industry received a major boost with the start-up of US midstreamer Kinder Morgan’s $1.75bn Gulf Coast Express (GCX) pipeline in late September. The 2bn ft³/d pipeline carries gas from Waha to the Agua Dulce hub near the Texas Gulf Coast. Such was the pipeline’s immediate impact, Waha hub gas prices rose to their highest levels in months in anticipation of its start-up, converging with other regional hubs.
“Capacity is being built, but maybe slower than anticipated or needed, which could prolong flaring” — Fulwood, OIES
According to the US federal energy regulatory commission (Ferc), spot Waha prices averaged just $0.68/mn Btu in August, while, by mid-September, January 2020 futures contracts for at the hub for January at $2.33/mn Btu in anticipation of GCX reaching capacity. While prices remain low, this marks a significant normalisation of basis differentials.
Operators immediately benefiting from the start-up of GCX include US independents Pioneer Natural Resources and Apache. Pioneer said in the firm’s third-quarter earnings call that it was moving c.300mn ft³/d of Permian gas to the Gulf Coast on the pipeline. Apache, meanwhile, credits GCX for helping the firm access “attractive marketing margins”.
This access was much needed, after Apache was forced to curtail some of its production at the gas-rich Alpine High project in the Permian in April owing to unfavourably low gas prices. The deferred volumes were only returned to production during the third quarter of this year—again illustrating the the impact of GCX start-up.
But GCX alone is not enough to address the Permian’s gas glut, with which producers are still struggling to deal, and which will continue to weigh on Waha hub prices in the near-term. Consultancy Rystad Energy concludes that flaring and venting levels in the Permian reached an all-time high of more than 750mn ft³/d on average in this year’s third quarter of 2019—an increase from an average of 600-650mn ft³/d during the prior nine months. Rystad attributes the rise to a combination of higher activity levels, increased production from areas with less developed gas-gathering infrastructure and ongoing takeaway capacity bottlenecks.
It is also common practice to flare associated gas at newly completed wells before they are tested, says Rystad’s head of shale research, Artem Abramov. “With this in mind, the level of flaring is set to stay quite high in the Permian as activity levels—completions/fracking—remain quite robust, so we get a lot of new wells every month,” he says.
Nonetheless, the slow pace of gas pipeline development is exacerbating the situation.
“Capacity is being built, but maybe slower than anticipated or needed, which could prolong flaring,” says Mike Fulwood, a senior research fellow at the Oxford Institute for Energy Studies (OIES).
Several pipeline operators have been engaged in efforts to address the shortage of takeaway capacity, and, in the longer-term, more relief is anticipated. The most advanced future projects are the 2.1bn ft³/d Permian Highway and 2bn ft³/d Whistler projects. Both are now scheduled to enter service in 2021, after Permian Highway’s start-up date was recently pushed back from the fourth quarter of 2020 by operator Kinder Morgan. Beyond this, additional pipelines of a similar capacity have also been proposed, although not all will be built.
Given the size of the planned pipelines, Permian Highway and Whistler alone are expected to offer considerable relief. “Producers will hope that this means an end to having to pay customers to take the gas, thus significantly improving Permian opex,” says Gneiss’ Simm.
Pipeline exports to Mexico offer another outlet for Permian gas, and there have also been some encouraging signs on this front with the September start-up of the 2.6bn ft³/d Sur de Texas-Tuxpan pipeline. However, much of the focus for those looking at target markets for Permian gas output has been on new LNG export terminals on the US Gulf Coast.
There are now four major LNG export facilities operating in relative proximity to the Permian—two in Texas and two slightly further away in Louisiana—with a further two having reached the final investment decision (FID) stage. The more trains that come online at these terminals, the more regional gas demand there will be.
“Producers will hope that this means an end to having to pay customers to take the gas, thus significantly improving Permian opex” —Simm, Gneiss
But, despite LNG exporters calling for significant additional pipeline capacity from the Permian and other shale regions, some questions remain over the need for new takeaway capacity in the longer-term. Earlier this year midstream firm NAmerico Energy Holdings pushed back FID on its Pecos Trail pipeline, citing the need to continue gauging shipper interest. Kinder Morgan has also slowed work on Permian Pass, its third major proposed gas pipeline out of the basin.
“We believe the pipeline is needed, but it may not be needed quite as soon as we were expecting three months ago,” Kinder Morgan’s CEO Steven Kean said on the firm’s third-quarter earnings call. His remarks indicate that, if the company proceeds to build Permian Pass, its start-up would be pushed out beyond 2022.
This comes as new worries are expressed about the Permian Basin’s longer-term potential and a possible slowdown in activity in the region. “It looks as though we could be getting close to the [production] peak in the next few years, although growth has been underestimated in the past,” says OIES’ Fulwood.
Permian producers are likely to press on as long as economics allow it. And to this end, any additional value linked to associated gas production will be welcomed. “Creating value from associated gas is a major plus for these guys and this value can effectively reduce the operating cost of producing oil from the play,” says Simm. “This should allow them to produce at lower oil prices, thereby continuing to generate more associated gas.”