Rapid development of unconventional natural gas fields in North America marks a true revolution for the energy industry.

Less than a decade ago, most industry analysts projected that the US would depend increasingly on imported liquefied natural gas (LNG). At the time, US gas production appeared to be in a state of decline, and Canadian output had hit a wall; even under the most optimistic scenario, Canada’s domestic consumption would eat into exports to the US. Canada’s booming oil sands industry was a particularly fast-growing gas consumer.

Most observers fretted over America’s ability to build LNG terminals quickly enough to meet growing demand for gas on both sides of the border.

Fast-forward to 2010. The biggest problem isn’t how to import more gas but what to do with the growing oversupply. Rapid production growth from fields such as the Barnett, Marcellus and Haynesville Shale has pushed US gas output to new heights. In 2009 the US overtook Russia to become the world’s largest gas producer.

And the contest wasn’t even close: The US produced almost 13 percent more gas than Russia in 2009, and the gap will widen in 2010. To put these figures into context, consider that the US alone produced almost as much gas as the entire Middle East and Africa combined. 

Even more amazing, US output has soared despite depressed natural gas prices. Check out this graph of US gas production since the late 1990s.

Source: Energy Information Administration

As you can see, US natural gas production fell from 2001 to 2005 but began to rise again in 2006. Even as natural gas prices plummeted in late 2008 and remained depressed throughout 2009, US gas production marched steadily higher.

The surge in US natural gas production has affected every corner of the energy industry. In some cases, the impact has been undeniably negative; for example, Cheniere Energy (AMEX: LNG) bet on rapid growth in US LNG imports and got crushed when cheap domestic gas flooded the market. After soaring to highs above $40 in 2007, the stock now trades at less than $3.

Cheniere Energy’s master limited partnership (MLP), Cheniere Energy Partners LP (NYSE: CQP), has held up far better than its parent thanks to long-term contracts covering the use of its LNG import terminal and high quarterly distributions. But Cheniere Partners remains a yield trap. The MLP may be able to maintain its payout over the next few years but has no real growth prospects, and its terminals are set to remain underutilized for the foreseeable future. Cheniere Energy Partners LP continues to rate a sell in our How They Rate Table.

The effect on other industries has been more ambiguous. For example, US-focused gas producers are now seeing production growth that appeared impossible a decade ago. But with prices depressed, rising output doesn’t necessarily translate into fast-growing profits.

But save a handful of exceptions like Cheniere, the shale-gas boom has been a significant positive for MLPs. As we’ve explained before, MLPs provide the infrastructure that makes the shale boom possible, including pipelines to transport gas, processing facilities and, of course, storage caverns to accommodate rising gas in storage.

In fact, identifying MLPs with significant leverage to the shale gas revolution has been a key investing theme of this advisor since its inception. This focused has produced some of our best-performing recommendations.

Given the continued weakness in natural gas prices and the negative investor sentiment toward gas-focused producers, it’s hardly a surprise that we’re often asked for our take on the long- and short-term outlook for gas prices. One of the most common questions we’re asked is whether the seemingly endless glut of gas could have any negative consequences for our favorite MLPs.

The Short-Term Outlook for Gas

The spot or front-month futures contract is the most common price of natural gas you’ll see quoted in the financial news.

The spot price of gas is simply the price you’d pay for a million British thermal units (BTU) of gas for immediate delivery. The front-month futures price is the first available futures contract; right now, that’s the October 2010 natural gas future traded on the New York Mercantile Exchange. The graph below depicts the rolling front-month gas futures contract since the end of 2005.

Source: Bloomberg

Natural gas prices are extremely weak right now, and the front month futures contract is probing new 2010 lows. In fact, prices have reverted to levels last seen at roughly this time one year ago. As you might expect, the weakness in front-month futures prices has soured sentiment toward many stocks leveraged to natural gas production, particularly natural gas-focused exploration and production firms.

But this front-month futures price isn’t that relevant to the industry’s fundamentals because natural gas prices are highly seasonal. Demand for gas is strongest in the winter months and weakest in the so-called shoulder season, the period between winter heating demand and summer cooling season. Gas prices tend to be higher in the winter months; in the two shoulder seasons in the spring and autumn typically bring the lowest prices.

October is the heart of shoulder season. Total natural gas in underground storage tends to peak in early to mid-November and decline as winter heating demand kicks in. Based on seasonal trends, October futures prices should be weak relative to prices earlier in the year; that the front-month contract recently sank below $4 per million BTU isn’t that surprising.

Fortunately, gas producers don’t sell all of their annual production in shoulder season. A more relevant measure of natural gas prices is the 12-month natural gas strip.

Source: Bloomberg

Gas futures are available that expire in every month of the year. The 12-month natural gas strip is the average price of the next 12-months worth of futures contracts. In this case, the 12-month strip would be the average price of every futures contract between October 2010 and September 2011. The strip is higher than the near-month futures price because it averages in the price of gas for delivery in the high-demand winter months.

The strip also makes more logical sense from a producer’s standpoint. Assuming a producer sells its output over the course of a year, the strip is the approximate average price they’d receive. And because most producers use the futures and forward markets to hedge production, the strip gives a good indication of prices a producer can lock in through hedges.

However, in this case, the trend in the 12-month strip isn’t much healthier than for the near-month futures. The price of gas recently slumped to its lowest levels since 2003-08 and is less than where it was at the height of the recession in late 2008-09. This pattern stands in stark contrast to the path of crude over the same period; oil prices have more than doubled from their 2008-09 lows and remain at historically elevated levels above $70 a barrel.

In the short term, fears or a repeat of last year continue to weigh on natural gas prices. In August and September 2009, US natural gas prices plummeted amid concerns that production would exceed storage capacity.

Natural gas is stored underground in salt caverns and in depleted natural gas fields. The nation has a large amount of storage capacity relative to other major gas-consuming and -producing countries partly because there are a large number of depleted oil and gas fields dotting the US.

But US storage isn’t infinite; the rapid rise in natural gas inventories one year ago pushed the limit of the nation’s capacity. At one point last autumn, pipeline operators were forcing producers to shut in wells because they didn’t have anywhere store new production. This glut sent near-month gas futures prices tumbling well under $3 per million BTU and pushed the 12-month strip lower as well. As you might expect, many gas-levered stocks were hit hard.

A repeat is highly unlikely this year because demand and supply conditions are more favorable than in 2009. Demand for natural gas from electric power producers has been elevated all summer.

Source: Energy Information Administration

This graph tracks consumption of natural gas by US electric-power producers over the past three years. There’s a clear seasonality to the data: Consumption is highest in the summer hear, and July and August are two key months to watch.

Although the US Energy Information Administration (EIA) releases data with a lag, electricity producers’ demand for natural gas is far higher in 2010 than it was in either 2008 or 2009. This is a function of two major factors. First and foremost, summer 2010 will go into the record books as among the hottest in the past three decades. The almost continual heat wave from Memorial Day to Labor Day drove record power demand–a stark contrast to the relatively cool summer 2009.

Second, there has been a significant amount of coal-to-gas switching. Electric power producers with the flexibility to use either coal or natural gas have used a bit more gas and a bit less coal this summer. For the most part this choice is driven by economics; cheap and falling gas prices encourage more demand for natural gas.

Even more important, weather conditions don’t entirely account for the uptick in demand; as we’ve written in previous issues, demand among industrial buyers continues to increase.

Source: Energy Information Administration

This graph compares industrial demand for natural gas in 2010 to the five-year maximum and five-year minimum. As you can see, industrial gas demand has trended toward the highest levels in five years. When you consider that this period includes the strong economic environment before 2007-08, that’s an impressive showing.

The boom in shale-gas production has been offset to some extent by unusually strong demand for natural gas in 2010; although natural gas storage levels are above average, the glut is nowhere near as pronounced as it was one year ago.

Source: Energy Information Administration

This graph depicts total US gas in storage compared to the five-year maximum and five-year minimum levels. At one point this spring, storage levels in the US set new five-year highs and were well above 2009 levels. But as the summer has progressed, the seasonal build in gas storage has actually been far less than normal. This effect has been particularly pronounced since early July, roughly the time when the US heat wave intensified.

Last year storage topped out near 3.9 trillion cubic feet before falling off sharply in November, when winter weather began to increase demand. However, unless there’s a prolonged period of milder weather in September and October, it’s unlikely that US gas in storage will match last year’s elevated levels. As such, last year’s storage concerns aren’t likely to make an appearance in 2010.

US natural gas prices should find a seasonal bottom over the next month or so.

Although near-term supply conditions in the natural gas market have hit sentiment surrounding US natural gas-focused producers such as Chesapeake Energy Corp (NYSE: CHK) and Cabot Oil & Gas Corp (NYSE: COG), our favorite MLPs should see little or no impact from the near-term price gyrations in natural gas.

The Aggressive Portfolio contains the names with the most exposure to commodity prices. Upstream MLPs such as Linn Energy LLC (NasdaqGS: LINE), EV Energy Partners LP (NasdaqGS: EVEP) and Encore Energy Partners LP (NYSE: ENP) produce significant quantities of natural gas and are exposed to weaker natural gas prices.

But there are some huge differences between these MLPs and other natural gas producers. As my colleague Roger Conrad explained in the previous issue of MLP Profits, most producer MLPs hedge their output several years into the future. These hedges lock in prices for gas, limiting exposure to near-term price swings.

And remember that although gas prices are currently near rock-bottom, earlier this year the 12-month strip traded north of $6 per million BTUs; many MLPs had the opportunity to add to long-term hedges and further blunt the impact of commodity-price volatility.

Aside from the handful of producer MLPs in the model Portfolios, most of our recommendations own storage facilities, pipelines and other midstream assets. These MLPs have no direct exposure to natural gas prices; the fees charged by pipeline operators are based on the volumes of gas transported, not the value or price of that gas. In fact, the seasonal uptick of gas in storage is a boon for MLPs that own storage facilities because demand for their services increases. 

Bottom line: MLP investors shouldn’t be concerned about the near-term weakness in US natural gas prices, as it should have little or no impact on the group.

Drilling Activity and Liquids

But MLP investors must be concerned with two fundamentals in the gas industry: drilling activity and prices for natural gas liquids (NGL).

As we’ve written before, one of the most unusual aspects of the shale gas boom is that US drilling activity has continued to pick up despite multiyear lows in front-month and 12-month strip gas prices. There’s no precedent for this phenomenon: In past cycles, low or falling gas prices have prompted drillers to cut back production.

Here’s a graph showing the US gas-directed rig count.

Source: Bloomberg

This graph shows the total number of rigs drilling for natural gas in the US. As you can see, the gas-directed rig count topped out around 1,600 rigs in August 2008 and fell sharply to a low of under 670 rigs in spring 2009. Since bottoming out, the gas-directed rig count has recovered to nearly 1,000 rigs even though gas prices haven’t recovered significantly.

The increase in the gas-directed rig count reflects an explosion of activity in unconventional gas plays such as the Haynesville and Marcellus Shale.

Two basic technologies have enabled the shale gas revolution: horizontal drilling and fracturing. Horizontal wells include a segment that’s drilled horizontal to the surface of the Earth.

We’ve written about hydraulic fracturing at some length in prior issues of MLP Profits. It’s a technique that involves pumping a liquid into a shale basin. The liquid physically cracks the reservoir rock and makes it easier for the gas to flow into a well. Without these two basic technologies, there would be no shale gas revolution.

The easiest way to measure activity in US shale plays is to track the horizontal rig count, or the total number of rigs actively drilling horizontal wells in the US.

Source: Bloomberg

As you can see, this graph of the horizontal rig count follows the same basic pattern as the chart of the gas-directed rig count, with two notable exceptions: The horizontal rig count is well above its summer 2008 highs, and the jump in the horizontal rig count has been far greater than the gain in the overall rig count since the spring 2009.

The traditional relationship between gas prices and drilling activity remains very much in place for conventional gas drilling using vertical wells; low gas prices have prompted producers in conventional fields to reduce activity.

But the same rules don’t hold for shale gas and horizontal drilling: This activity has picked up markedly despite weak prices.

Also note that only a portion of the overall gain in the US horizontal rig count is due to a pick-up in gas drilling activity. Some of the gains are a function of an unprecedented jump in the number of rigs targeting crude oil in the US.

Source: Bloomberg

The jump in the oil-directed rig count is logical. Crude oil prices have risen dramatically since the spring 2009. With prices averaging between $70 and $80 per barrel over the past few quarters, producers are drilling more aggressively to boost output.

But crude oil production also benefits from the shale-gas revolution. Many of the most prolific shale plays in the US contain significant volumes of crude, as well as natural gas and natural gas liquids. Other shale plays such as North Dakota’s Bakken Shale are exclusively crude oil plays. Producing oil from unconventional fields involves the same basic technologies as producing gas: horizontal drilling and hydraulic fracturing.

The jump in natural gas and oil-related drilling activity is a major positive for MLPs. Many MLPs own gathering systems, small diameter pipelines used to connect individual gas and oil wells to the national pipeline network. Higher drilling activity means more wells to be hooked up to the gathering system and a higher volume of oil and gas traveling through gathering pipelines. MLPs with gathering systems in place near the hottest shale plays stand to benefit the most.

Sustainability is one potential question mark. It’s highly unusual for the gas-directed rig count to increase when the price of natural gas hovers near multiyear lows. In a normal environment, we’d expect an imminent decline in drilling activity that would, in turn, negatively impact MLPs with exposure to gathering pipelines.

But this isn’t a normal environment. A few major factors have supported the US gas-directed rig count this year and should prevent a collapse in activity going forward.

• Economics: The value of NGLs improves the economics of many of the largest shale-gas plays.
• Efficiency: Production from unconventional fields is cheaper than production from conventional vertical wells. Drilling, fracturing and other services have become more expensive over the past few quarters, but much of that cost inflation has been offset by efficiency gains. Producers continue to reduce the time and investment required to drill wells in unconventional fields as they gain experience.
• Held-by-Production Drilling: Many leasing contracts contain clauses that force companies to begin producing gas from their leaseholds within a specific time frame or forfeit these claims. These terms prevent producers from leasing a bunch of land and sitting on it until gas prices are attractive. Producers continue to drill even though the economics of gas production have deteriorated.
• Hedges: Many producers hedge at least a small percentage of their output, limiting exposure to spot or near-month gas prices. Hedges improve profitability.

We’ve discussed all of these factors at some length over the past several months. Some of these drilling supports should begin to fade into the latter half of 2011. In particular, several producers have commented on the importance of drilling contracts that mandate continued drilling in order to hold leases. CEO Aubrey McClendon’s comments during Chesapeake Energy’s second-quarter conference call are particularly instructive:

I would say that once the carries are used and the acreage is HBP [held by production], then we look to move into a much different mode. And we’ve already said that $6 [per million BTUs] is our bogey and so we look forward to a time a year from now, for example in the Haynesville when most of our acreage will be HBP and if we need to, we can begin gearing down. In the Fayetteville [Shale of Arkansas], I remind you our drilling has gone down by half 17 rigs to 8 rigs as we’ve reached the point where we can comfortably kind of glide in to a finished HBP position. So, that will occur next in the Barnett after the Haynesville and then next after that in the Marcellus.

So I’ve said it many times before, but a large portion of the industry drilling right now for gas anyway is involuntary as it works with HBP leasehold. And most of those leasehold positions were established in 2006, ’07 and ’08 and the time to finish HBP in that acreage will be this year and next year and after that, I think the industry moves into a much different drilling phase.

Most held-by-production (HBP) lease arrangements have a term of around three years; mandatory drilling on leases signed in 2008 would need to be completed by 2011 to hold acreage. McClendon expects this involuntary drilling to continue into 2011 but taper off afterward.

And McClendon’s comments were by no means unique; other major natural gas-focused producers made similar statements. This trend suggests that the gas-focused rig count could decline or at least flatten in the back half of 2011.

Hedges also suggest that drilling activity will cool in 2011. Many producers had hedges in place covering production in 2009-10, many of which were taken on in mid-2008, a period of sky-high natural gas prices. The expiration of these hedges means that a growing percentage of producers’ output would need to be sold at depressed spot prices.

Many subscribers have asked me what gas prices are needed to support profitable drilling in US shale plays. There’s no easy answer to this question because it depends on the particular field, the quality of the acreage and the producer’s experience. It also changes over time based on service costs and gains in efficiency.

However, McClendon offers a good rule of thumb that echoes statements from other producers. Minus the artificial support of HBP drilling and hedges, producers need the 12-month strip to hit $6 per million BTUs to ramp up gas-focused drilling activity. This break-even point is significantly lower than the $8 per million BTUs needed to incentivize an uptick in conventional gas production.

Although fading hedges and HBP drilling should moderate the US rig count in the latter half of 2011, the US won’t suffer an outright collapse in drilling activity. Don’t expect this shift to have much of a negative impact on our favorite MLPs.

Strong NGL and oil prices should continue to support drilling activity. Oil-focused drilling activity has been particularly strong in recent months, and as long as oil prices average above $65 per barrel, this strength should continue.

Many producers, including Chesapeake Energy, won’t stop drilling altogether as their involuntary HBP drilling obligations expire. Instead, most producers intend to shift drilling budgets away from pure gas production toward plays that feature oil and NGLs. This reallocation of capital spending will simply shift activity from gas to oil drilling.

And don’t forget that the $6 per million BTUs inflection point applies to dry-gas production. Many of the most exciting US shale-gas plays also contain significant volumes of NGLs–mainly propane, butane and ethane. Because the price of a barrel of NGLs is roughly correlated to the price of a barrel of oil, the value of these NGLs improves the economics of gas production immensely. Some producers estimate that NGLs add as much as $2 in value to each thousand cubic feet of gas produced.

The economics of oil and NGLs pricing looks solid. Check out the graph below.

Source: Bloomberg

This graph compares the price of a barrel of West Texas Intermediate crude oil to a barrel of NGLs.

Although US crude oil inventories remain bloated, the global picture looks far brighter. Global oil demand is rapidly increasing, led by growing demand from emerging economies such as China, India and Russia. Meanwhile, demand in the developed world continues its cyclical rebound from the depths of the 2007-09 recession.

The supply picture is mixed. OPEC officially has significant spare capacity, but these numbers are likely overstated; many OPEC producers are cheating on their official quotas and have a tendency to overestimate production capacity.

Meanwhile, the cost of non-OPEC supply is rising. Output from cheap and easy-to-produce onshore oilfields continues to decline, forcing producers to focus their attention on deepwater fields. The US Gulf of Mexico, long considered a key source of non-OPEC oil production growth, will also be negatively impacted by reduced oil drilling and stricter regulations in the wake of the controversial drilling moratorium. Crude oil prices are likely to remain elevated for some time to come.

There are legitimate concerns that a boom in unconventional gas production will also bring a surge in NGL production that could weigh on pricing.

Such a scenario is unlikely. As I noted in On Track, the July 27 issue of MLP Profits, US chemicals companies are stepping up their use of NGLs and cutting back on the consumption of naphtha derived from crude oil because NGLs are cheaper and more readily available. This looks to be a secular shift that should continue for years to come.

And NGL volumes are easily exported. Excess inventories of NGLs in the US can be alleviated by stepping up exports to other countries with limited supply–and prices higher prices. Judging from the jump in NGL exports this year, that’s already happening.

On average, a barrel of NGLs trades at just under 60 percent of the value of a barrel of oil; with the current ratio at 57 percent, that price relationship isn’t notably breaking down.

Strong liquids-focused drilling activity is a major positive for the MLPs because it spells rising demand for oil and NGLs gathering, storage and transport. In addition names such as Enterprise Products Partners LP (NYSE: EPD) and Targa Resource Partners LP (NYSE: NGLS) have heavy exposure to gas processing and fractionation (the removal of NGLs from raw natural gas). These businesses benefit directly from strong NGL demand and pricing.

Some MLPs are also making major investments to accommodate the producers’ shift to more liquids production. A perfect example is last week’s announcement that Enterprise Products Partners will build a 140-mile long pipeline to transport crude oil from the liquids- and oil-rich Eagle Ford Shale of South Texas. To support this project, Enterprise Products Partners signed a 10-year deal with one of the largest producers in this region, EOG Resources (NYSE: EOG).

In addition to providing crude oil transportation services, Enterprise will handle NGL processing, transport and storage for EOG’s operations in the Eagle Ford. With EOG planning to double its activity in the region, Enterprise stands to enjoy major volume growth once the new pipeline is completed in 2012.