Uncompleted Wells as Seasonal Natural Gas Storage

As natural gas prices remain depressed, not only at Henry Hub but especially in the oversupplied Appalachian basin, industry watchers are paying a lot of attention to break-even pricing and looking for E&Ps to scale back drilling and completions in order to bring the domestic gas market back in balance.

We’ve already seen the beginning of this process, with capital budgets being trimmed, and even shut-ins of existing production. However, the simplest way for oil and gas producers to access better pricing in the future is just to delay completion of existing wells already drilled. This is becoming increasingly common, with operators like Chesapeake (™¢CHK 5.03 +0.14 2.97%), Range (RRC 40.61 +0.62 1.55%), Antero (AR 27.70 +0.47 1.73%), and others in the Marcellus and Utica reporting a backlog of uncompleted wells awaiting better prices.

For prices to improve, these operators are looking to either pipeline expansions to be completed, or demand growth. As for pipeline expansions, Spectra’s (SE 36.69 +0.11 0.31%) OPEN project came into partial service last month, allowing more gas flow from Appalachia to the Gulf Coast. With Henry Hub now under $2.50, the upgrade received by shippers Chesapeake, CNX, and Rice is probably less than what was hoped for when the capacity was subscribed.

As for demand growth, E&Ps look to winter to get an upgrade in price. Right now, January Henry Hub is just over $2.80/ MMBtu. While this provides a bit more of an upgrade, one wonders how much investment in additional completions can be justified to bring gas to the Gulf this winter.

Ideally, E&Ps hope to access high-demand market areas like New York, New Jersey, and Boston and their correspondingly high prices. Several projects in the next few years  promise to open pathways to these markets. However, these deliveries only command significant premiums to Henry Hub in the winter months. For instance, Transco’s zone 6 market area (New York) commands a $3.23 premium to the benchmark for this coming winter, but is actually trading at a $0.63 discount for next summer. Similarly, Algonquin Citygates, representing Boston gas deliveries, fetches a $5.10 premium for this winter, and are flat to Henry Hub for the summer. This is due to the huge swing between summer and winter gas demand in the region, with a peak winter day now more than 40 Bcf/d, and summer lows under 15 Bcf/d. Unfortunately, exports may only exacerbate this seasonality, since LNG will most likely have a similar load profile over time, as the anticipated markets are in the northern hemisphere and lack significant storage capacity.

So what is a producer to do?

We can look back to history to venture a guess. In the late 1980’s and early 1990’s, Texas was the dominant natural gas production area in the country, but lacked infrastructure to export to demand centers elsewhere in the country. Summer price crashes were so common that producers became accustomed to shutting in volumes, to await a winter rebound.

Source: EIA

Source: EIA

During this period from 1989 to early 1993, Texas averaged 760 MMcf/d more gas production in the winter months than in the summer. Taken over the course of an entire summer, this was an effective 163 Bcf “stored” each year.

The current situation in the northeast US is quite a bit larger in scale, but has more offsets thanks to a more developed national natural gas infrastructure. Exports from the region to Gulf LNG terminals, summer demand centers in the South and Midwest, plus storage injections will soak up much of the excess in the summer, but price crashes have shown that there may still be a good deal of summer oversupply in Appalachia.

Shutting in fields is a dramatic decision. It’s costly and can have serious implications on reservoir performance, not to mention cash flows. However, timing drilling and completions schedules so that wells tend to come online in Q3 and Q4 makes a lot of sense. High decline rates mean that volumes may taper in time for the following summer, and again await completions until the next fall. If Northeast producers begin to follow this pattern, then 0.1 to 0.5 Tcf of additional implied gas storage is conceivable.

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