New power plants in Mexico have spurred natural gas demand south of the border––and fast-rising gas imports from the U.S, particularly Texas. Thus far, pipeline exports from Texas to Mexico have primarily been supplied by gas produced within the Lone Star State, but a big squeeze is on as nearby Texas production volumes decline (particularly the Eagle Ford) and export demand continues to increase, not just from Mexico but from new liquefaction/LNG export terminals along Texas’s Gulf Coast. Today, we unpack the shifting Texas supply and demand balance and potential implications for the market.
This is Part 3 of our “It Takes Two” series. We started in Part 1 with an overview of developing trends in Mexico’s natural gas market. In short, for some time now, Mexico’s thirst for natural gas has been growing. The state-owned Comisión Federal de Electricidad (CFE) has been feverishly expanding its fleet of natural gas-fired combined-cycle power plants, and there are big plans to build a gas pipeline network to feed them. No less than 800 miles of gas pipelines are under construction and another 2,500 miles are on the way to facilitate utilization in the power sector, including seven projects totaling 8.0 Bcf/d of transport capacity that have been awarded contracts for construction, all with in-service dates in 2017 or 2018. Several of the pipeline projects—either under construction or awarded—originate at or near the Texas-Mexico border and extend south or west to connect with other projects and Mexico’s existing mainlines, all with the expectation that Mexico’s revamped power generation fleet will rely in large part on supply from Texas. In fact, even as Mexico’s natural gas consumption has been on the rise, its domestic production has slowed. So barring a reversal in that supply trend, much of the incremental gas demand will need to be met by imports. The U.S. midstream sector is jumping to take advantage of this growing demand center. As we discussed in Part 2, six pipeline projects totaling nearly 8 Bcf/d upstream of Mexico’s natural gas pipelines on the U.S. side are in various phases of development to move gas from Texas’ Agua Dulce Hub in South Texas and from Waha Hub in West Texas into Mexico, all due in service by 2019. With these plans progressing on both sides of the border, all signs point to continued growth in Mexico demand and higher exports to Mexico. However, as we also noted in Part 2, several stars must align for all this capacity to translate to a corresponding jump in export flows. The increased exports are predicated on Mexican power and pipeline projects materializing as currently planned and also assumes Mexican gas production will continue to lag. The other key dependency is that sufficient natural gas volumes must be able to navigate Texas’s intrastate and interstate pipelines to reach the border crossing points.
Up to this point, that cross-Texas capacity has been available. The only real limiting factor for U.S. natural gas exports to Mexico thus far has been the lack of gas demand and/or infrastructure within Mexico, available capacity from Agua Dulce to the border (met in December 2014 by NET Midstream’s NET Mexico Pipeline), and by Petróleos Mexicanos’ (Pemex) ability to meet most of the country’s gas needs. Until early 2014, Texas production was still in growth mode, even as growing Marcellus/Utica supply in the Northeast was increasingly pushing back on northeast-bound supply from Texas. The Energy Information Administration’s (EIA) annual production data shows Texas supply grew by a total of 2.5 Bcf/d between 2010 and 2014, a 14% increase over the five-year period—not quite the pace of growth seen in the five years prior to 2010 (the early shale boom era), but still a significant amount of growth, considering that the Marcellus/Utica supply grew by more than 13 Bcf/d in that 2010-14 time frame. The supply growth in Texas––especially in the latter half of that period––was primarily driven by associated gas from oil- and liquids-directed drilling in the Eagle Ford and Permian producing areas, as by then natural gas prices were low but oil and liquids prices alone provided plenty of incentive to continue drilling. But of course, that all changed with the oil price collapse starting in mid-2014, a topic we’ve written about extensively in the RBN blogosphere. It took some months for the effects of that price collapse to show up in production volumes—there are always efficiency gains to be had (see Sooner or Later)—but the impact to rig counts was swift. Rig counts in more mature shale plays like the Barnett and Haynesville, which had essentially ushered in the shale gas boom, had already petered out and remained sparse. But the rig count in the Eagle Ford was cut in half, from more than 200 in December 2014 to just over 100 in mid-2015 and to 33 rigs as of this Friday, October 28, according to Baker Hughes rig count data. In the Permian, which had substantially more rigs than Eagle Ford to begin with at its peak (nearly 570 in December 2014), rig counts fell off a cliff to about 230 by mid-2015 and by another 100 to about 130 by mid-2016 (although as noted below, 80 rigs have since come back to the Permian – Friday’s rig count was 212).