The Alerian Index rose 14 percent in the third quarter. As you might expect, holdings in our Aggressive Growth Portfolio outperformed in this strong market; based on a straight average of returns, the portfolio soared 20.5 percent during the quarter.
Most master limited partnerships (MLPs) have little business exposure to commodity prices. Pipelines are the most common assets held by MLPs; fees earned on these assets typically depend on the volume of oil or natural gas traveling through their lines, not the value of the commodity itself. Even when volumes transported do fall, those drops are often offset through automatic inflation-indexed tariff increases. (That was borne out this year when gasoline and jet fuel volumes tailed off).
Many investors assume the only MLPs with exposure to commodity prices are those that produce oil and/or natural gas, such as Aggressive Growth Portfolio holdings Linn Energy (NSDQ: LINE), EV Energy Partners (NSDQ: EVEP) and Legacy Reserves (NSDQ: LGCY). But that leverage is not as dramatic as you might suppose thanks to significant commodity price hedges. For example, Linn Energy has hedged most of its production through the end of 2011 and significant volumes into 2014. That’s why Linn has not cut its distributions despite natural gas prices touching multi-year lows earlier this year.
Although Legacy and EV Energy Partners have some exposure to commodity prices, both have relatively high distribution coverage ratios. That means that they’re not paying out all of their free cash flow to unitholders and have a cushion of cash to cover distributions should commodity prices retreat.
There is one sector of the MLP universe that’s more exposed to commodity prices than the producers over the near term: Gathering and Processing (G&P) MLPs. The two holdings in the Aggressive Portfolio involved in this business are Williams Partners (NYSE: WPZ) and Regency Energy (NSDQ: RGNC).
The G&P business weakened significantly in early 2009, weighing on distributable cash flows and prompting a handful of G&P MLPs to cut their distributions. Stronger MLPs such as our two favorites maintained their payouts, but investors paint the entire group with the same brush–Regency and Williams both offer higher-than-average yields despite relatively modest risk.
And with the G&P business showing signs of improvement there’s a growth kicker: Regency and Williams stand well-placed to grow their distributions again significantly in the coming year. Investors are beginning to appreciate the potential for recovery; G&P MLPs, including our two favorites, were among the top performers in our coverage universe in the third quarter.
Gathering lines are small-diameter pipelines that connect individual natural gas and oil wells to processing facilities and, eventually, the interstate pipeline network. MLPs typically charge a fee based on the volumes of oil or natural gas they gather and, by extension, the number of wells they hook up to their gathering systems.
When commodity prices are strong, US producers tend to drill aggressively for oil and gas. The more aggressively producers drill, the more wells they need to hook up to gathering systems and the more demand there is for MLPs to expand their networks.
The health of the gathering business is closely tied to the active rig count, a measure of how many drilling rigs are actively drilling for oil or natural gas. Because roughly 70 percent of US drilling rigs target gas, the most important metric is the US gas drilling rig count pictured in the graph below.
The US gas rig count collapsed starting in August 2008 as natural gas prices tumbled. The fall in the rig count accelerated into early 2009 amid a severe credit crunch that hit smaller producers’ ability to fund planned drilling programs. As gas prices continued to fall, more US gas fields became uneconomic to produce; producers shuttered wells and discontinued drilling, causing volumes of gas traveling across gathering systems and demand for new well hook-ups to tumble.
The US natural gas rig count has recovered slightly from a low of 665 rigs in July to 712 rigs more recently. But the drop from 1,606 rigs last August was the fastest and most dramatic fall in gas drilling activity on record. For this reason, gathering volumes have likely remained depressed through the third quarter but should stabilize going forward along with the rig count.
Over the long term, the key to a recovery in gathering volumes is a rise in US natural gas prices that would prompt producers to bring rigs back to work. Natural gas prices have been weak this year, primarily due to a glut of gas in storage–US natural gas in storage hit a new all-time record this week and will likely continue rising until winter heating season arrives in early November. Storage levels are so high that pipeline operators are limiting the amount of gas they’ll accept for transport, forcing producers to shut in wells.
Supply and demand factors are behind the gas storage issue, specifically a big surge in production from US gas shale plays through early 2009 and a slump in industrial demand for gas due to the weak economic environment. But there are clear prospects for improvement in both the demand for and the supply of gas. In fact, this improvement is already reflected in natural gas prices.
This graph tracks the 12-month NYMEX natural gas strip. There are gas futures that expire in all twelve months of the year; the 12-month strip is nothing more than an average of the next twelve months of natural gas futures prices.
Unless you’re actively trading natural gas futures, the 12-month strip is more meaningful than near-month gas futures or spot gas prices. That’s because producers don’t sell all of their gas production in the month of October and won’t decide to increase or pare back their drilling activity based solely on the price of gas in October.
Even as most pundits and the financial media talked about gas prices plunging to seven year lows in September, the reality was quite different. As the chart above shows, the strip bottomed out earlier this year and generally has traded sideways since January. And over the past few weeks, the strip broke to its highest levels since January, a meaningful improvement.
The strip is rallying for two main reasons. First, the big drop in drilling activity I noted earlier is finally starting to manifest itself in the form of falling US natural gas production. The Energy Information Administration (EIA), a unit of the Dept of Energy, releases US gas production data on a monthly basis but with a two-month lag. That means the most recent data, released in late September, is for the month of July.
This graph tracks the month-over-month change in total US natural gas production. It’s clear the production declines are accelerating.
Some unconventional gas shale plays such as the Haynesville Shale in Louisiana are still economic at current natural gas prices; in fact, Louisiana gas production actually rose in July thanks to continued drilling activity in Haynesville.
However, other plays, such as the Barnett Shale in Texas, aren’t economic. Barnett’s production is likely already falling sharply, and Texas produces a large amount of natural gas from conventional fields that require gas prices above USD6 to USD7 per million British thermal units (MMBtu) to be profitable.
Production in Texas–by far the largest gas-producing state in the union–has plummeted by nearly 2 billion cubic feet per day this year. Production fell 1.2 percent in July compared to June levels.
The second support for a rally in gas prices will be a recovery in demand. Most of the drop-off in gas demand this year is attributable to weak industrial demand, which typically accounts for between 35 and 40 percent of America’s total natural gas demand.
As you might expect, industrial demand is tied to the health of the US economy and, in particular, to the health of manufacturing activity.
This graph of the year-over-year change in Industrial gas demand shows several cycles since 2002. The first relatively sharp downturn in industrial demand came during the short, shallow recession early this decade.
The second downturn, in late 2005, was due to a spike in natural gas prices after Hurricanes Katrina and Rita. When gas prices spiked and gas supplies were interrupted, manufacturers capable of switching to other fuels did so. Fuel switching coupled with outright gas shortages meant that in late 2005, industrial demand for gas dropped year-over-year at a greater than 15 percent pace.
The most recent downturn is more pernicious and intractable: The so-called Great Recession of 2008 caused industrial activity to slow at the most dramatic pace since the 1974 recession.
But the data in the above graph is only updated through July and already shows a meaningful slowdown in the rate of decline in industrial gas demand. That does not mean that industrial demand rose in July, but the rate of decline appears to be moderating.
And indicators of manufacturing activity, such as the Manufacturing Purchasing Managers’ Index (PMI) and Industrial Production, are good, timely proxies for industrial gas demand.
This graph depicts the current Manufacturing Purchasing Managers’ Index. Levels above 50 indicate expansion in manufacturing activity; levels below 50 indicate contraction. Because the most recent data is for the month of September, this provides a more up-to-date read on industrial gas demand than the EIA numbers.
PMI plunged to a low of 32.9 in December 2008, indicating that industrial activity was in free-fall–in light of that reading it shouldn’t come as a surprise that natural gas demand collapsed. But PMI has soared back above 50 since midsummer, indicating that activity is rising. PMI suggests that we’ll continue to see improvement in industrial gas demand in EIA numbers for the next few months.
In summation, the natural gas strip is hitting multi-month highs, and the US gas-directed rig count has bounced off its lows. This suggests that the market is beginning to price in falling gas production and stabilizing demand. Although gathering volumes are likely to remain weak in the third and fourth quarters of this year, the data suggests 2010 will bring a recovery. That confluence of factors is why MLPs with gathering exposure have been outperforming the Alerian Index of late.
Processing is the equivalent of refining for the natural gas industry. Gas processors take raw gas and strip out natural gas liquids (NGLs) such as ethane, propane and butane. Gas processors can also take a further step, known as fractionation, to separate the individual NGL components.
Gas processors make profits based on the relative value of NGLs and natural gas. Because processors essentially buy natural gas (a cost) and produce and sell NGLs (revenue), the higher NGL prices are relative to natural gas prices, the more profitable the processing business is.
Some G&P MLPs are not directly exposed to volatile processing margins. Many G&P MLPs have fixed-fee contracts; in other words, they’re paid a fee based on the volume of gas and NGLs processed. But when gas processing margins are high, demand for processing services rises; even in a fee-based arrangement, there is some indirect exposure to margins.
Other G&P MLPs earn at least a percentage of their processing revenues based on processing margins and the relative prices of gas and NGLs.
The processing business also suffered last year and into early 2009. Check out the graph of butane and ethane prices below.
The first graph shows normal butane prices in cents per gallon, while the second shows ethane prices in the same terms. Prices for these key NGLs collapsed in the second half of 2008; at times late last year and early in 2009 it was more profitable to simply leave NGLs in the natural gas stream (to the extent allowed by natural gas pipeline standards) than to strip out the NGLs and sell them separately.
NGL prices remain far below the record high levels witnessed in the middle of last year but have rallied significantly since the beginning of the year. Processing margins are similarly below their 2008 highs but are back in positive territory.
NGLs are liquid fuels and, therefore, NGL prices tend to track crude oil prices more closely than natural gas prices even though they’re derived from gas. The rally in oil from below $40 a barrel to recent highs over $70 a barrel has helped NGL prices to recover. NGL prices have not recovered as quickly as oil but continue to follow crude more broadly.
That brings me to a final graph.
This graph shows the 12-month natural gas strip divided by the 12-month NYMEX crude oil strip. For the most part, the gas/oil ratio is meaningless; natural gas is primarily used for heating and electricity production, whereas oil is mainly used for transport. The one market where the fuels are potentially interchangeable involves NGLs and petrochemicals.
Companies can derive petrochemicals such as ethane and butane from crude or gas. When gas prices are cheap relative to oil, gas processors generally benefit because natural gas is the cheaper, and therefore preferred, feedstock.
A low gas/oil ratio usually translates into relatively high processing margins because processors buy gas and produce NGLs that tend to be correlated to oil prices–a low gas/oil ratio means that processors costs are low and selling prices high. As the above graph illustrates, the gas/oil ratio is an important positive for processing margins in the near term.
To make a long story short, the outlook for processing markets is reasonably strong and has been improving. Although the recent jump in gas prices will tend to depress margins by pushing up feedstock costs, the ongoing uptrend in NGLs pushes up the revenues processors earn from selling NGLs. A rebound in manufacturing and industrial markets would tend to push up NGL prices further; NGLs are used by the chemical industry to produce plastics and other products.
As we outlined in the July 16, 2009, issue of MLP Profits Gathering Yields, we’re playing the G&P recovery conservatively for now with Williams Partners and Regency Energy.
These two G&P MLPs have a number of advantages over other partnerships in the business. First, both have strong sponsor firms–Williams (NYSE: WMB) for Williams LP and General Electric (NYSE: GE) for Regency–that have consistently supported them during the G&P downturn.
Williams has totally foregone incentive distribution fees for 2009 that would normally be paid to Williams by Williams LP. There’s widespread speculation that they’ll announce another suspension for 2010 if the G&P business doesn’t improve further. And Williams also has a large number of assets it could sell to Williams LP to boost distributable cash flow if needed.
GE was able to help Regency finance a key pipeline project in the Haynesville Shale earlier this year. This project is essential to the MLPs long-term growth.
Another advantage for both MLPs is that they own gathering assets in regions where the drop-off in drilling activity has been less pronounced than in the country as a whole. For example, drilling in the Haynesville Shale has remained robust this year because it’s one of the only fields in the US profitable with gas prices under $4 per million BTUs. Regency’s assets in the region have been less negatively impacted than gathering systems serving conventional fields in Texas and Oklahoma.
And both Williams and Regency have enough cash and unused borrowing lines to see them through the downturn even as over-leveraged G&P MLPs have been forced to cut their payouts. We’re boosting our Buy targets on both stocks to reflect continued strong prospects for growth.We have also begun to upgrade our ratings on some smaller, riskier G&P-focused MLPs in our How They Rate coverage universe. If NGL and gas prices continue recent recoveries, some of these beaten-down MLPs could resume distribution growth and reinstate dividends. We may look to add one such MLP to our Aggressive Portfolio in an upcoming issue of MLP Profits.