U.S. natural gas exports drove a significant portion of overall gas demand growth in 2016 and are expected to continue being the primary demand driver over the next several years. Much of this export demand will be emerging along the Texas-Mexico border and at planned LNG export terminals along the southern Texas Gulf Coast. But production in the South Texas region is not expected to grow nearly as quickly or robustly as demand, setting the stage for supply constraints and premium pricing in the South Texas market and making the area a target destination for producers and pipeline companies. For example, on Wednesday, Enterprise announced the possibility of a new pipeline from Orla, TX, in the Permian Basin to Agua Dulce in South Texas. So how will all of this play out? Today, we continue our series analyzing the gas supply and demand balance in South Texas, this time with a look at the demand side and the resulting market balance.
This is Part 2 of our blog series looking at the impact of growing natural gas export demand on gas flows and pricing in the South Texas market. As we noted in Part 1, South Texas is poised to emerge as a premium destination for growing U.S. gas supply over the next few years, driven by demand from new LNG export capacity along the Texas Gulf Coast, as well as power and industrial demand in Mexico. These changes have the potential to create constraints and volatility in the market. To identify the extent and timing of these potential constraints, we began with a supply and demand analysis of the region. Using the regional definition described in What It Takes, we quantified four main components of the supply and demand balance: 1) how much “local” gas supply is available; 2) how much local demand needs to be served; 3) how much supply is left over after meeting local demand; and 4) how much export demand there will be. Estimating each of these components gives us a good idea of how long or short supply South Texas will be as demand grows and how much new pipeline capacity would be needed to balance the supply/demand equation. It is that balance which will in turn will indicate price direction in the region.
In Part 1, we started the analysis with the first component—prospects for supply growth within the region. As we noted, about 80% of regional gas supply comes from the Eagle Ford Shale while the other 20% comes from non-shale drilling activity. Since incremental production will almost entirely come from the shale side, we focused our supply analysis specifically on trends in the Eagle Ford. That shale play used to be one of the fastest growing in the U.S., led by oil- and liquids-focused drilling. That is, until 2014 when oil prices collapsed. Rig counts fell by more than 200 to a low of 29 by mid-2016. It took a while for production volumes to be affected, but by October 2016, output from the Eagle Ford was (down by about 1.0 Bcf/d (~20%) to approximately 4.4 Bcf/d, from 5.5 Bcf/d in 2015. Since last October, however, we have started to see evidence of a turnaround. Rig counts are staging a rather steep comeback, as seen in the latest rig count numbers from Baker Hughest (Figure 1).
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