During the past several years, overinvestment in prolific US shale plays has produced an abundance of natural gas supply. The resulting glut caused the price of that commodity to plummet as low as $1.91 per million British thermal units (MMBtu) back in late April. Since then, the price of natural gas rebounded as much as 104 percent to $3.90 per MMBtu, though contracts have settled more recently near $3.46 per MMBtu.

The question is what confluence of supply and demand factors will finally reward all this output? In the near term, a decline in production growth coupled with the increasing use of natural gas for power generation should sop up significant supply. And longer term, the prospect of exporting liquefied natural gas overseas holds promise.

Meanwhile, the price of natural gas has risen sharply since April, as production growth decelerated and low prices enticed electric utilities and large industrials to switch from coal to natural gas. Both of the aforementioned factors have slightly more than halved the inventory of natural gas since the beginning of April to 3.7 trillion cubic feet.

Year to date through the end of September, US natural gas consumption averaged 59.7 billion cubic feet per day (bcf/d), up 9.4 percent from the prior year. Utilities were responsible for about 45 percent of that demand, utilizing 26.7 bcf/d on average, a 28.4 percent jump from a year ago. Industrials accounted for almost 31 percent of demand at 18.5 bcf/d, a level consistent with a year ago

However, the natural gas inventory is still 9 percent above the five-year average. And through mid-September, production was up 5.2 percent year to date versus a year ago, though that rate of increase is a clear slowdown from prior years.

Unfortunately, a normal winter may not be enough to sufficiently deplete inventories. Indeed, analysts estimate such a winter would still result in natural gas supply that’s almost 14 percent above average. In fact, this winter will need to be 12 percent colder than average to draw down inventories to normal levels.  

So far this season, the warmer-than-average weather has failed to accommodate. Since Nov. 1, the total withdrawal of natural gas has amounted to 205 billion cubic feet, which is almost 22 percent below the five-year average during this period. A total withdrawal of 2.3 trillion cubic feet by April 1 will be necessary to reduce inventories to their long-term average.

At the same time, the switch from coal to natural gas becomes a less compelling option for electric utilities as natural gas prices rise. Analysts have noted that the peak of switching activity coincided with the commodity’s low in April and slackened considerably once prices climbed above $3 per MMBtu. That assessment was bolstered by American Electric Power Co (NYSE: AEP) management’s comment during its recent earnings call that utilities start to switch back to coal once natural gas prices are between $3 and $3.25 per MMBtu.

And if the price averages $4 in 2013 that could further crimp demand among utilities. In fact, the Energy Information Administration projects utilities’ demand for natural gas could drop as much as 2.64 bcf/d from the 2012 average of 28.9 bcf/d.

On the other hand, roughly 4,335 megawatts (MW) of coal-fired power generation is slated for retirement over the next two years. That’s more than offset by another 8,300 MW of gas-fired capacity expected to commence operating next year. Longer term, business consultancy Navigant predicts utes’ demand for natural gas will rise 55 percent to 44.8 bcf/d by 2035.

But that’s in the distant future. At least for next year, the smart money appears to be betting that natural gas prices will remain weak. Recent data from the Commodity Futures Trading Commission (CFTC) show that traders’ net long positions have more than halved since their peak in July. Analysts’ consensus forecast for the average price of natural gas in 2013 is $3.70 per MMBtu, which is about 7 percent higher than where it trades presently.

On the supply side, producers have begun shifting their efforts toward exploiting oil and natural gas liquids until natural gas inventories return to normal levels. And this tilt away from natural gas production is best evidenced by the dramatic decline in the rig count over the past year. The current gas rig count stands at 388, down nearly 49 percent from a year ago.

Longer term, the ability to export liquefied natural gas (LNG) to overseas markets could be a meaningful driver for domestic prices. In fact, the price for natural gas, particularly in Asia, far exceeds prices in the US. Some estimates suggest that even after costs for transportation are taken into account, gas producers could book $10 per MMBtu in profits from exporting to Asian markets.

At present, the infrastructure for exporting our domestic bounty to far-flung markets is virtually non-existent. The problem is that LNG export facilities face two huge hurdles: 1) It costs as much as $2 billion to build such infrastructure for each 0.68 bcf/d worth of capacity, and 2) these facilities face fierce local political opposition.

According to the US Energy Information Administration, 20 applications to develop such infrastructure have been submitted to the government, totaling 30 bcf/d of potential capacity. But based on the travails of Cheniere Energy Partners LP (NYSE: CQP), whose $5 billion Sabine Pass facility is scheduled to commence operations in late 2015 or early 2016, many of these projects may not come to fruition. In fact, Navigant forecasts just 6.8 bcf/d in LNG exports by 2020.

For these reasons, MLP Profits remains largely focused on master limited partnerships (MLP) whose businesses are essentially toll takers, such as midstream operators and shippers. These MLPs tend to be well insulated from volatile commodity prices because they generate fees based on long-term contracts for simply transporting commodities such as natural gas to end markets. And some of these contracts even include capacity payments that ensure fees regardless of whether an MLP’s assets are fully utilized.

That’s why our most conservative recommendations have a record of growing distributions over the long term, as opposed to payouts that fluctuate wildly depending on commodity prices.