Permian gas prices will remain weak for the next few years despite nearly 2 bcfd of additional pipeline capacity coming online by 2020. This is because the Permian, predominantly a shale oil play, has large quantities of associated gas production. We expect Permian crude and NGL production to grow from 3.3 MMb/d in 2017 to 8.8 MMb/d by 2025—which in turn is expected to cause natural gas production to rise from 7.1 to 16.0 bcfd over the same time frame.
The Texas Gulf Coast and, to a lesser extent, Mexico are the most likely destinations for incremental Permian gas volumes. While the fundamentals support additional pipelines (i.e., large quantities of new gas being produced), there is a real risk that the Permian will become over-piped in the medium to long-term. As private equity looks to fund the next major pipeline project, they will be increasingly drawn to projects linking the Permian to the demand centers in the US Gulf Coast. This is because pipelines typically offer stable revenue, and the regulatory risk is minimal in an oil and gas friendly state like Texas. Combining favorable fundamentals, minimal regulatory risk, and private equity, there is a real risk that too much capacity will be developed in the long term.
Conventional economics do not apply to unconventional associated gas
For all the excitement the Permian basin enjoys, it poses a major problem to gas markets. Depending on the year, an increase in oil production due to oil prices rising $10/bbl would also cause associated gas production from the Permian to increase by 1-2.5 bcfd. With sufficient gas pipeline capacity, this inexpensive associated gas would displace gas from other basins, causing US gas prices to drop by about $0.10/mmbtu.
If pipeline utilization exiting the Permian remains below 80 percent, in-basin gas prices are expected to be about $0.10/mmbtu cheaper than on the Texas Gulf Coast, because of the variable cost of transporting the gas (see Exhibit 1, D). Once pipeline utilization exceeds 80 percent, in-basin prices start to decrease as Permian gas competes with other gas for access to this limited pipeline capacity, causing in-basin prices fall further (see Exhibit 1, D). The Permian has already crossed that 80 percent threshold, and prices are starting to show the effects.[[exhibit 1]]
This scenario would usually result in operators reducing drilling for gas, but only approximately a quarter of Permian gas production is not associated with oil and is sensitive to in-basin gas prices. If in-basin gas prices fall, the first to be affected will be the <5 percent of production that comes from new gas wells, which have a breakeven of between ~$2–3/mmbtu (see Exhibit 2, C). Next would be the ~25 percent of Permian production from gas wells that have already been drilled, which break even at about $0.80-1.00/mmbtu (see Exhibit 2, B). The remaining ~75 percent of gas production is associated with oil, and can even have a negative value, as oil revenue is what drives investment decisions for those wells (Exhibit 1, A). Since this associated gas is largely unaffected by in-basin gas prices, we can expect to see Permian gas production continue to increase even as the takeaway capacity approaches 100 percent.[[exhibit 2]]
Where will incremental Permian gas production go?
There are two primary destinations for incremental Permian gas: Mexico and the Gulf Coast. Once bottlenecks are resolved, new pipelines to Mexico should add an effective export capacity of about ~2.9 bcfd, a much-needed outlet until new pipelines to the Gulf Coast come online from 2020 (see Exhibit 2). The other destinations for Permian gas are to the west and north. However, both routes face problems. Building additional pipeline to the west is difficult, especially in California, while western gas demand is uncertain due to higher solar generation. Meanwhile, competing volumes from the Marcellus and SCOOP/STACK, as well as higher pipeline development costs for long-distance interstate pipelines, makes building a pipeline to the north less attractive.
Too much of a good thing?
In other areas, we have seen anecdotal evidence indicating private equity money competes against itself, causing the required returns to fall. Additionally, Appalachia provides a good example of how excess pipeline can develop in response to wide basis differentials. (McKinsey Energy Insights models indicate there is more pipeline capacity exiting Appalachia than production until after 2026.)
Most of the proposed new pipelines linking the Permian to the Gulf Coast would be regulated as an intrastate (i.e., within Texas) pipeline and are generally easier to permit and build compared to interstate, or even northeastern interstate pipelines. Furthermore, private equity companies are increasingly attracted to stable pipeline revenues—especially when those pipelines are in an energy-friendly state like Texas, where a pipeline can be expected to come online 12-18 months after FID. As a result, it is more likely in the long term that excess new pipeline capacity will be built from the Permian to the Gulf Coast rather than too little.
LNG exports could provide additional demand for incremental Permian gas
Assuming there is sufficient pipeline capacity, high oil prices may not depress prices in the Permian as much as expected. This is because a $10/bbl increase in oil price leads to an increase of about $1.20/mmbtu in oil-linked LNG (assuming a 12 percent slope), with no direct impact on Henry Hub-linked US LNG prices. From 2020 to 2024, we expect about 2 bcfd of surplus capacity at US LNG export terminals. If oil prices were to increase due to, for example, a decrease in Venezuelan crude oil production or some other unforeseen shock, then oil-linked LNG contracts would become more expensive. Demand for US LNG would become more price competitive and provide an outlet for additional associated Permian gas.
The Permian is in a unique position. High oil prices lead to additional gas production and put downward pressure on in-basin gas prices. The Permian’s gas problem can be divided into two phases. The first phase is from now until about 2020 where there is insufficient pipeline capacity and in-basin prices are low. Despite building nearly 2 bcfd of additional pipeline capacity by 2020, additional capacity is needed. This leads to the second phase. Market fundamentals may attract too many pipelines, and the Permian is at risk of becoming over piped.