Cars and airplanes don’t run on crude oil; crude must be refined into products like gasoline, diesel and jet fuel before use.
The same is true with natural gas: Raw natural gas produced from a well isn’t the same as the natural gas that you burn in your home or the gas that’s used to produce electricity in power plants. And natural gas produced in different regions of the US or different parts of the world can have varying properties, characteristics and economic value.
Natural gas, once processed and shipped to your home for use, primarily consists of methane, a simple hydrocarbon molecule that’s a single atom of carbon bonded to four hydrogen atoms (CH4). But methane doesn’t usually occur in a pure form in the nature; CH4 is normally found with other hydrocarbons and mixed with other gases.
Often, natural gas–known as associated gas–is found dissolved in crude oil. Associated gas remains dissolved as long as the oil is under geologic pressures, but as the oil is produced, it tends to bubble out of the crude. The action of natural gas bubbling out of crude aids in oil production in much the same way that carbon dioxide bubbles in your Coca-Cola or sparkling water can power the liquid out of a bottle. The oil industry refers to this action as bubble drive.
In other parts of the world, natural gas isn’t associated with oil but contains significant quantities of impurities such as carbon dioxide, water vapor, nitrogen or hydrogen sulfide that must be removed before the gas is suitable for use. The latter impurity, hydrogen sulfide, is a poisonous and highly corrosive gas; natural gas that contains a large amount of hydrogen sulfide is known as sour gas, and the removal process is known as sweetening.
Natural gas also occurs naturally with a series of hydrocarbons known collectively as natural gas liquids (NGLs). These can be differentiated by the number of hydrogen atoms they contain–for example, ethane (C2H6), propane (C3H8), butane (C4H10) and natural gasoline (C5 and higher). The table below offers a rundown of the typical composition of raw natural gas from a well.
This list is far from exhaustive; gas from different fields can have very different characteristics in terms of NGL content and composition. For example, gas from the deepwater Gulf of Mexico is typically wet or rich gas, meaning that it contains a high volume of NGLs. Meanwhile, gas produced from the Haynesville Shale is often dry gas, meaning that it is low in NGLs and high in methane content.
This is a meaningful distinction for producers. Historically, the price of a barrel of NGLs has tracked the price of crude oil more closely than the price of natural gas. When gas prices are low relative to oil–a condition that prevails today–the sale of NGLs produced from gas can offer a meaningful and often overlooked boost to profitability.
The existence of NGLs and impurities in natural gas is also of great importance for MLPs.
MLPs own natural gas treatment and dehydration plants that remove water, sulfur and nitrogen from the gas stream. And MLPs are among the largest owners of natural gas processing and fractionation facilities; processing involves the removal of NGLs from raw gas, while fractionation involves the separation of the NGL stream into distinct hydrocarbons. For example, a fractionation plant would isolate and separate the ethane, butane and propane in the NGLs stream for individual sale.
Finally, NGLs are transported via dedicated pipelines and stored separately from natural gas. NGLs can also be liquefied into liquefied petroleum gas (LPG), loaded onto ships and exported abroad or to other parts of the country. MLPs own significant NGL transport, storage and export infrastructure.
The Shale Opportunity
In the Dec. 18, 2009, issue of MLP Profits, Shale Infrastructure, we explained how the boom in gas production from unconventional natural gas plays is opening up attractive growth opportunities for MLPs in a number of areas. One such opportunity is the construction of pipelines to transport gas out of fast-growing unconventional plays such as the Haynesville Shale of Louisiana.
But the build-out of natural gas treatment, processing and fractionation infrastructure is just as important. As I explained earlier, the composition of raw gas from different regions differs widely.
Source: “Compositional Variety Complicate Processing Plans for US Shale Gas,” Oil & Gas Journal, March 9, 2009, pp. 50-55.
The table details the composition of multiple wells for both the Marcellus and Barnett shale plays and a single “average” level for the Haynesville, listing the percentage of methane and a handful of key NGLs and common impurities.
The Marcellus Shale is located in Pennsylvania and West Virginia; the Barnett is located near Fort Worth, Texas; and the Haynesville is located in Louisiana and across the border into east Texas. At the time this data was compiled, the Haynesville Shale was still relatively early in its development compared to the Marcellus and Barnett. Since then, the Haynesville has become one of the hottest and fastest-growing gas plays in the country.
In the case of both the Marcellus and Barnett Shale, the composition of gas from wells varies widely between different parts of the play. In both areas, the gas is drier on the eastern side of the play and richer in NGLs in the western reaches. The major difference between the Marcellus and Barnett Shale wells listed is that the Marcellus wells have a lower concentration of impurities such as carbon dioxide and nitrogen. Thus, Marcellus gas wouldn’t require much treatment but does require processing to remove NGLs.
In addition, natural gas from conventional gas fields in Appalachia is extremely dry; historically, these wells haven’t required much treatment or processing. Because gas from the Marcellus is high in NGL content, the area requires the construction of substantial processing and related infrastructure.
The average Haynesville well consists of dry gas, though it’s relatively high in carbon dioxide; it would require treating to remove CO2. Comments from some producers suggest that wells in certain areas, particularly east Texas, have higher NGL content.
Just as it’s important to build gathering systems to collect gas in emerging shale plays and pipelines to move that gas to market, producing these areas also necessitate the construction of additional processing, treatment and fractionation infrastructure. This build-out is already underway in several parts of the country, and MLPs are leading the charge.
Processing and Fractionation
The economics of the processing, treating and fractionation business depend on commodity prices. Most MLPs in the industry have fee-based arrangements with producers that guarantee some revenues even when processing economics aren’t attractive. And most use extensive financial hedging to shield against near-term swings in oil, gas and NGLs pricing.
Nonetheless, MLPs involved in these businesses have varying degrees of exposure to processing economics; it’s important to understand the trends underway if you’re going to invest in the group.
One of the most useful price relationships to keep in mind is the ratio of natural gas prices to crude oil. We’ve published this chart before in MLP Profits, but here’s another look.
To create this graph, I converted oil prices from their traditional quotation of dollar per barrel ($/bbl) to dollars per million British Thermal Units ($/MMBTU). In this way, crude oil prices can be compared directly to natural gas prices. I then divided the price of oil per MMBTU by the price of gas. A ratio of 2-to-1, for example, means that oil costs twice as much per BTU as a BTU from natural gas.
As you can see, the current price of oil is close to three times that of natural gas on an energy equivalent basis. This is a near-record level for this ratio.
Why is this important? The price of a barrel of NGLs has traditionally tracked the price of a barrel of crude more closely than it has natural gas prices. Accordingly, when crude oil prices are high relative to gas, NGL prices are likely high relative to gas; in such an environment processing and fractionation services would be in high demand, as companies seek to maximize their NGL output and take advantage of those high prices.
MLPs can be compensated for their processing services in a number of different ways.
Under fee-based contracts, a processor receives a straight fee based on the volumes of gas it processes. In this instance, there’s little direct exposure to processing margins, but demand for gas processing can drop when NGL prices are low. That’s because companies don’t have to remove all of the NGLs and impurities in the gas stream; they only have to remove enough NGL content to comply with pipeline requirements.
In addition, one way to make wet gas compliant with pipeline standards is to blend it with dry gas, diluting the NGL content; when NGL prices are low, volumes of gas processed can still drop. Nevertheless, fee-based deals are considered the least commodity-sensitive type of processing contract.
Under keep-whole deals 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 margins 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.
Most MLPs mix and match these different types of contracts to limit their commodity exposure, but under all of these arrangements, a high crude-to-gas ratio is desirable.
The price of NGLs tends to track crude in a normal environment; the relationship traditionally has been so tight that processors have routinely used crude oil futures, swaps and options as a proxy for NGLs when hedging their exposure. But as every investor knows, the past 18 months have been far from normal. The graph below provides a closer look.
This graph tracks the price of a barrel of crude oil and NGLs since late 2004. The latter price is based on a common mixture of ethane, propane and butane.
Note that the graph uses two different scales to illustrate the tight relationship between the two commodities; this does not mean the prices are identical, but that they are closely correlated over time.
At present, the price of a barrel of NGLs is worth just under 60 percent what a barrel of crude oil is worth. The long-term average is around 62 to 63 percent; the current crude oil to NGL ratio is at a normal, healthy level.
But in late 2008 and early 2009, this relationship broke down on a few occasions. The lowest recorded ratio occurred in October 2008, when the price of a barrel of NGLs sank to 45 percent of the price of a barrel of crude–perhaps a product of weak demand for NGLs from the petrochemical industry.
It’s clear that the ratio of oil to gas prices is now favorable and the ratio of NGLs to oil prices has reverted to traditional levels–great news for MLPs involved in gas processing and fractionation.
These fundamentals are consistent with the bullish comments that Enterprise Products Partners’ (NYSE: EPD) management made concerning its fractionation and NGLs business during its recent conference call. We discussed those comments at length in the Feb. 26, 2010, issue of MLP Profits, Distribution Upside. To summarize, management noted that demand for ethane from petrochemicals producers remains strong and that inventories of propane and other NGLs are relatively low.
In addition, check out the graph below for a look at export demand.
Source: Energy Infromation Administration
In its conference call, Enterprise noted strong demand for exports of NGLs in the form of liquefied petroleum gas. Data from the US Energy Information Administration (EIA) indicates that, at least through December, demand for NGLx exports from the US has been near historic highs. Strong domestic and export demand for NGLs is good news for pricing–and for the economics of any MLPs involved with the NGL supply chain.
How to Play It
Many MLPs have some exposure to processing and NGLs supply, but only a few names offer significant leverage.
Conservative Portfolio holding Enterprise Products Partners (NYSE: EPD) is one of the largest players at all levels of the NGL supply chain, from processing to NGL marketing. As we noted in Distribution Upside, this segment of Enterprise’s business was the key to Enterprise’s better-than -expected performance in the fourth quarter.
Although exposure to processing and fractionation would normally mean significant commodity sensitivity, Enterprise Products Partners is an exception. That’s because partnership favors a conservative mix of processing and fractionation contracts with a heavy fee-based component. And after last year’s acquisition of TEPPCO diversified Enterprise Products Partners’ operations; when processing margins are weak, it has plenty of other business lines to pick up the proverbial slack. Buy Enterprise Products Partners up to 33.
Targa Resources Partners (NSDQ: NGLS) offers the most exposure to the NGL supply chain in our coverage universe. The company gathers and processes natural gas from three primary regions: the Permian Basin in West Texas, the Fort Worth Basin and the Louisiana Gulf Coast. The company’s assets in the Fort Worth Basin give it some exposure to volumes produced from the Barnett Shale of Texas, the most established of the shale plays. In total, the gathering system consists of 6,500 miles of pipelines in these three regions.
Targa Resources Partners also owns seven processing plants with a total throughput capacity of 673 million cubic feet of gas per day. In 2009, these plants produced an average of about 42,700 barrels of mixed NGLs per day.
The partnership is heavily exposed to margins because most of its processing contracts are percent-of-proceeds and keep-whole arrangements rather than fee-based deals. In fact, roughly 77 percent of its gathering and processing deals are percent of proceeds; 20 percent are keep-whole deals; and just 3 percent are fee-based–the lowest exposure of any MLP in our coverage universe to fee-based arrangements.
Processing economics are strong, though Targa Resources Partners has suffered a decline in gathering volumes over the past year due to weak US natural gas prices.
Also, like most MLPs, Targa Resources Partners deploys an extensive hedging program to reduce its risk associated with commodity prices. The vast majority of the partnership’s 2010 exposure to natural gas and NGLs prices has already been hedged, but the size of Targa Resources Partners’ hedge book gradually declines through the end of 2012, providing partial coverage of volumes. Management will likely expand the hedge book opportunistically over the coming months to reduce volatility.
These hedging strategies aren’t unusual. What differentiates Targa Resources Partners from the pack is the partnership’s diversified exposure to the entire supply chain. Most of these so-called “downstream” NGLs businesses were acquired last year from the company’s general partner, Targa Resources, a privately held company that’s one of the country’s largest owners of midstream assets.
Targa Resources Partners paid $530 million to acquire the downstream assets, while its parent agreed to guarantee the partnership’s distribution through the end of 2011. It’s unlikely that the MLP will call upon this backstop, but if the partnership’s distribution- coverage ratio falls under 1.0, the parent will provide up to $8 million per quarter to ensure unitholders receive scheduled payouts.
By diversifying into downstream NGLs businesses, Taiga Resources Partners will profit from the strong processing margins and high demand for NGLs from petrochemical producers today. And the acquisition reduces the partnership’s reliance on processing margins; 75 percent of the MLP’s downstream fractionation and marketing contracts are long-term, fee-based arrangements with little exposure to commodity prices.
On the downstream side of the business, Targa Resources Partners owns three fractionation facilities outright and controls 88 percent of a fourth plant that it operates. The MLP also has a one-third stake in a final fractionation facility that another firm operates. These plants are located in Lake Charles, Louisiana and Mont Belvieu, Texas–areas near the heart of the US NGLs industry.
To handle all of this NGL production, Targa Resources Partners owns significant storage and terminal assets, including four underground NGL storage facilities and 15 above-ground terminal facilities. The MLP also has access to rail and barge transport to move NGLs to and from its facilities as needed.
The final segment of the MLP’s business is NGL distribution and marketing. This consists of selling NGL volumes that the partnership produces at its own facilities, as well as buying and reselling NGLs from producers. The partnership usually purchases raw, mixed NGLs from producers at a certain pricing index, minus fees for fractionation, transport and marketing services. After fractionation, these NGLs are sold to petrochemical producers and other industries. These marketing arrangements are all done under contract and are primarily fee-based, reducing risk.
Targa Resources Partners issued a total of 6.3 million new units in January, raising about $145 million in capital after fees. This deal was expanded from a planned 5.25 million unit offering because of strong investor demand for the issue, a sign that the partnership’s financial position is solid. Management used some of the proceeds to repay debt and plans to invest in several growth projects this year, including the expansion of its Cedar Bayou fractionation facility in Mont Belvieu. This project is backed by long-term, fee-based contracts that should generate a steady stream of cash flow.
In addition, management has indicated that it’s looking to expand the partnership’s footprint in US shale plays via acquisitions. With plenty of undrawn capacity on its credit line and a proven ability to raise cash via unit issues, Targa Resources Partners could make this plan a reality
The MLP covered its distribution a hefty 1.6 times in the fourth quarter, and the coverage ratio should average 1.3 in 2010. Given an ongoing recovery in the NGL business and organic expansion, the partnership could increase its distribution toward the end of 2010 or in early 2011.
With its units yielding nearly 8 percent, Targa Resources Partners rates a buy in How They Rate.
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