But there is one midstream energy business that has a degree of commodity exposure: gathering and processing (G&P). The G&P business can be extraordinarily lucrative when US drilling activity is robust and oil and gas prices are relatively high. But when drilling activity collapses, as it has over the past 10 months, this business can take a hard hit. In fact, most of the master limited partnerships (MLPs) that have cut their payouts over the past six months have done so due at least in part to G&P exposure.

But don’t make the mistake of assuming that any exposure to G&P is a negative. Conservative portfolio bellwether Enterprise Products Partners (NYSE: EPD) has a significant G&P business but remains among the steadiest, low-risk MLPs in our coverage universe. Enterprise mitigates its G&P risks through effective hedging, long-term fixed-rate contracts and overall business diversification.

And a handful of smaller MLPs with heavy G&P exposure currently offer an attractive value proposition for more aggressive investors: yields that range between 10 to 15 percent and the potential for rapid distribution growth as commodity prices recover. The best G&P-focused MLPs grew their distributions by more than 20 percent annualized in the commodity bull market of 2005 through 2008; similar growth is likely during the next run-up. 

The Business

Gathering lines are small diameter pipelines that connect individual oil and natural gas wells to the nation’s pipeline network. Gathering line operators are generally compensated based on the number of new wells they hook up and total volumes of oil or gas transported over their systems.

Accordingly, the profitability of the gathering business is directly tied to US drilling activity and the number of new wells being drilled. The gathering line network in a particular region must expand as more wells are drilled to handle the incremental volumes of oil and gas produced from those wells.

Gathering line operators don’t own the natural gas or oil they transport; small changes in commodity prices likely will have little or no effect on profitability. However, when commodity prices rise or fall enough that it impacts drilling activity, the gathering business is affected. The following chart shows the Baker Hughes (NYSE: BHI) US active drilling rig count over the past few years.

Source: Bloomberg

This chart shows the total number of rigs actively drilling for oil or natural gas in the US over time. This chart offers a good general proxy for the health of the gathering business–when the rig count is rising that’s bullish for gathering.

The rig count ran up sharply in early 2008 when oil and gas prices soared but collapsed amid the 2008 commodity slump and credit crunch. Over the past few weeks, however, the rig count appears to have stabilized at a low level; it appears the worst may be over for the gathering business.

Two additional points are worth noting about the gathering business. First, about 75 percent of all drilling rigs in the US currently target natural gas, not crude oil; gas prices are the most important determinant of the rig count’s moves and, ultimately, the health of the gathering business.

Second, the gathering business is regional, not national.  Some gas reservoirs in the US are more expensive to produce than others; drilling activity in certain parts of the US will slow to a crawl as soon as gas falls below $9 per million British thermal units (MMBTU)–the level at which drilling becomes unprofitable. Meanwhile, other regions of the US enjoyed robust activity this year until gas prices fell under $4/MMBTU. Therefore, it is important to look at where a company has gathering systems when evaluating business risk.

The gas processing business is similar in some respects to the refining industry for crude oil. When first produced, raw natural gas is composed primarily of methane but also includes a number of other hydrocarbons and impurities. For example, raw natural gas might contain carbon dioxide, water vapor and sulfur-based gases–all of which must be removed prior to placing the natural gas in the US pipeline network.

Besides methane and these impurities, raw natural gas also typically contains a number of hydrocarbons such as propane, butane, ethane and natural gasoline. These additional hydrocarbons in raw natural gas are collectively termed natural gas liquids (NGLs).

Before natural gas can be placed in the interstate pipeline network, many of these impurities and NGLs must be removed so that the gas complies with standards governing purity and energy content. In addition, NGLs often have more value sold separately as chemical or refinery feedstock rather than burned as natural gas. For example, ethane is used to produce plastics and many other NGLs help boost the octane content of gasoline.

Gas processors remove NGLs and impurities from gas. A second step, known as fractionation, allows the individual NGLs in the gas stream to be isolated and separated.

The gas-to-oil ratio is a widely watched determinant of processing activity. Historically, the value of a barrel of NGLs has tracked the price of crude oil; when crude oil is expensive relative to natural gas, processors extract and fractionate as many NGLs as possible from the raw natural gas stream. Conversely, when oil prices are low relative to the price of gas processors typically leave more NGLs in the natural gas stream subject, of course, to regulations governing pipeline-quality natural gas.

Here’s a chart of the natural gas-to-oil ratio over the past few years.

Source: Bloomberg

As you can see, the current price of crude oil is near record highs relative to natural gas. This means that removing NGLs from the gas stream is profitable at the current time.

There is one caveat: The relationship between the value of NGLs and oil has broken down in recent months; processing profitability is not as high as you would expect given the current low gas-to-oil ratio. However, it’s still fair to say that the profitability of processing has improved in recent weeks.

G&P MLPs typically own processing and fractionation plants as well as pipelines used to transport NGLs. Companies can be compensated from performing processing and fractionation services in several different ways. I’ll review three of the most common types of contracts: fee-based contracts, keep-whole contracts and percent of proceeds (POP) contracts. 

Under fee-based contracts, a processor receives a straight fee based on the volumes of gas it processes. This is by far the most defensive and commodity-insensitive contract because there’s no direct exposure to processing profitability.

The term keep-whole pertains to the energy content of raw natural gas processed. In other words, the producer sends a certain amount of natural gas to the processor, and that gas contains a certain amount of energy on a British Thermal Unit (BTU) basis. Some of those BTUs are in the form of natural gas (methane), while others are locked up in NGLs that are part of the gas stream. 

With keep-whole contracts, the processor accepts natural gas from the producer but retains title to the NGLs it removes from the gas stream. In exchange, the processor gives the producer the value of natural gas with the same BTU content as the original raw gas. For example, assume a producer sends a processor 2 million BTUs of gas consisting of 1.5 million BTUs of natural gas and 0.5 million BTUs worth of NGLs. Under a keep-whole arrangement, the producer would retain the value of 2 million BTUs of pure natural gas and the processor would own and sell any NGLs removed.

When the price of NGLs is high relative to the price of gas, keep-whole deals generate significant margin for the processor. That’s because the value of the NGLs they keep is worth more than the natural gas they return to the producer.

In percent of proceeds (POP) contracts, raw natural gas is processed and the resulting gas and NGLs sold. The producer and processor agree on how to divvy up total proceeds of NGLs and gas. For example, the producer might accept 80 percent of the total value of the gas and NGLs sold and pay the processor 20 percent for performing its services.

Under POP deals, processors benefit from higher gas and NGLs prices; the processor is less interested in the relative values of gas and NGLs–the total value of the products is key.

One final point to note: most G&P MLPs use hedges to insulate their cash flows from swings in commodity prices. For example, a processor with heavy exposure to POP contracts might decide to sell both natural gas and oil futures to lock in prices for the NGLs and gas it sells.

How to Play It

We already have a modicum of exposure to G&P in the MLP Profits Portfolios. Enterprise Products Partners (NYSE: EPD) operates in this space, but this activity represents only a small portion of its total business. The partnership has also reduced its risks from G&P in recent years by focusing more on simple fee-based processing deals that remove exposure to commodity prices.

In addition, Aggressive Portfolio holding Regency Energy Partners (NSDQ: RGNC) and Growth Portfolio holding DCP Midstream (NYSE: DPM) have exposure to the business. For both companies, however, G&P is only part of their overall business and both firms have exposure to exciting new pipeline projects that will further reduce their exposure to G&P.

For a more direct and higher yielding play on G&P, consider Williams Partners LP (NYSE: WPZ). Although Williams Partners carries significant business risk because of its exposure to G&P, the MLP has the ongoing financial support of its general partner (GP), Williams Companies (NYSE: WMB).

The partnership divides its business into three operating units: G&P West, G&P Gulf and NGL Services. G&P West consists of gathering lines and processing facilities in the San Juan Basin located in New Mexico and Colorado. In fact, Williams LP is the largest gatherer in the San Juan Basin;  its lines averaged a throughput of 1.36 trillion BTU/day in the first quarter of 2009.

In total, Williams connects more than 6,000 individual wells in the region. Operations in this region are collectively known as Williams’ Four Corners assets; the San Juan Basin is located near the point where four states–Utah, New Mexico, Arizona and Colorado–come together in a single point.

The company’s western business also includes its ownership interest in the Wamsutter system, a 1,700 mile natural gas gathering system in Wyoming. Although depressed gas prices may temporarily halt drilling plans in this region, there is insufficient gas gathering infrastructure in place to handle potential production once gas prices normalize–longer-term, this is a growth area for Williams.

Williams’ G&P Gulf business includes its 60 percent ownership interest in the Discovery Pipeline, a 105 mile long offshore pipeline that extends from Louisiana into the Gulf of Mexico. The partnership’s Discovery assets also include a series of subsea gathering pipelines that connect individual wells to the Discovery mainline and a number of onshore gas processing and fractionation facilities that handle the gas as it comes onshore.

Discovery serves a number of the prolific deepwater gas fields that have been put into production in the Gulf of Mexico in recent years. There are also several new discoveries in the Gulf that are under development and will be brought into production in coming years; these new fields offer opportunities to expand the Discovery gathering system and transport and process more gas volumes.

The G&P Gulf business also includes a series of offshore pipelines and processing facilities related to the Carbonate Trend off the Alabama shore. Gas from this region is sour, meaning it contains a high concentration of dangerous and corrosive sulfur gases that require significant additional processing.

Given Williams’ heavy focus on G&P, the MLP is exposed to commodity prices and processing profitability. The partnership has never cut its quarterly payout and stated back in late April that it intends to maintain its $2.54 annualized payout this year. However, Williams LP’s cash flows have shrunk as a result of commodity exposure; the MLP’s cash distribution coverage–the amount of excess cash it has after paying its distribution–has fallen from 1.25 times its total distribution in early 2008 to just 0.9 times in the first quarter of 2009.

Clearly, cash distribution coverage of less than one isn’t sustainable over the long-term–Williams didn’t generate enough cash to cover its payout in the depressed commodity price environment of the first quarter. However, there are a few offsetting factors that lead us to believe Williams will maintain its distribution this year and is well placed to benefit from commodity price upside into 2010.

First, the commodity price environment has become far more hospitable since the first quarter. In the first quarter of this year, oil prices averaged just $43 a barrel and a barrel of NGLs sold for roughly $24. Crude oil now trades closer to $60 a barrel and NGLs fetch close to $32 a barrel. Management estimates that with an oil price of $60 and an NGL price around $36 a barrel, it would cover its distribution roughly 1.5 times. 

More important, Williams LP has the proven support of its General Partner, Williams Companies, a diversified natural gas company with a $9 billion market capitalization and a “BBB minus” credit rating from S&P. Back in April, Williams Companies announced that it would waive all incentive distribution rights (IDRs–the fee an MLP pays its general partner for managing its assets–that it is due from Williams LP this year. This amounts to about $30 million per year, a far from meaningless sum when you consider that Williams LP only needs around $140 million per year to pay its current distributions.

We also see the potential for Williams LP to acquire additional assets from Williams Companies or other firms. When Williams Companies first created Williams LP, it sold assets into the MLP and stated that it would continue to do so in future quarters; Williams is using the MLP as a growth vehicle. However, acquisition activity collapsed in in 2008 thanks to the weak capital market conditions we described in our July 2 Viewpoint, “Rising Income.”

But that’s all changing as the credit markets are once again functioning. Another G&P-focused MLP with arguably more sensitivity to commodity prices, Targa Resources (NSDQ: NGLS), priced a $250 million bond offering earlier this month and announced it’s in talks to acquire assets from its general partner. This suggests that it’s now possible for Williams to acquire more assets from its GP or to raise capital and buy new assets from other firms at attractive terms. Such a deal would likely shore up distribution coverage.

With a yield of 13.5 percent, Williams Partners is pricing in the risk of a distribution cut even though such a cut is unlikely–unless commodity prices return to their 2009 lows. With the support of its parent and improving capital markets, Williams LP should be in a great position to grow its payout in 2010 amid a more normal commodity price environment. We’re adding Williams Partners LP to the Aggressive Portfolio as a buy under 23.