The prices of key energy-related commodities have fallen sharply since mid-summer, though both oil and natural gas have bounced off their lows in recent weeks.

But despite that weakness, recent reports from our favorite energy-focused publicly traded partnerships (PTP) have been solid. As noted in last week’s Market Update, nearly every single one of the PTPs recommended in The Partnership Portfolio has boosted distributions paid to investors at least once over the past 12 months, and several have already declared increases in their payout for this quarter. And every one has equivalent or better distribution coverage than was the case a year ago.

A total of 40 PTPs in the Alerian MLP Index have announced third quarter distributions. Of those, nearly 80 percent have announced increases in their quarterly distributions.

Although commodity prices may have a short-term impact on market sentiment surrounding PTPs, the effect on cash flows for most in the group is negligible or non-existent. Here’s a rundown of what’s in store for oil and gas and how it’s affecting some of our favorites.

The driver of the fall in crude since mid-summer is simple: demand. The latest Oil Market Report for the International Energy Agency (IEA) projects that oil demand from the developed world will fall by nearly 1.1 million barrels per day (bbl/d) in 2008 and a further 600,000 bbl/d next year. The decline has been led by a slowdown in the US; US oil demand is likely to decline close to 1 million bbl/d in 2008.

This drop in demand has offset, to an extent, continued growth in demand from developing countries such as China and India. In 2008, the developing world is projected to see total growth in oil demand of more than 1.5 million bbl/d; that growth rate is projected to fall slightly in 2009 to about 1.3 million bbl/d.

The net effect of falling developed world demand and rising demand in emerging markets is a slowdown in global oil demand growth stretching into 2009.

The chart above shows year-over-year growth in global oil demand going back to 2001. It’s clear that oil demand growth for 2008 and 2009 is projected to be the slowest since the last recession in 2001. Falling demand is obviously not a positive for oil prices.

There are, however, mitigating factors. Chief among those is supply. Some of the world’s largest and most prolific fields are seeing falling production. A classic example is Mexico.

According to statistics released by Mexican state-controlled oil giant Pemex, total Mexican production is off 13 percent this September over the same month a year ago. As a result, Mexican crude oil exports have plummeted close to 40 percent year over year to just over 1 million bbl/d.

The main culprit in this decline is Cantarell, one of the largest onshore oilfields ever discovered anywhere in the world. Back in 2004, Cantarell produced more than 2 million bbl/d, but Pemex’s latest data shows that production has held at less than 1 million bbl/d for three consecutive months.

The same basic story is being repeated all over the world. The North Sea, Russia and parts of Africa have all experienced faster-than-expected declines in crude oil production from older fields. In fact, according to a recent report from the Financial Times, a study to be released by the IEA later this month will reveal the most conclusive evidence yet that production from mature oilfields globally is falling far faster than previously believed.

And there’s another factor governing supply: price. According to most oil services companies, the $70 to $80 per barrel range is a key level for many oil producers. While big integrated oil firms such as ExxonMobil (NYSE: XOM) and Chevron (NYSE: CVX) will go ahead with projects even with oil in the $50’s, smaller independents in markets like the US and North Sea begin to scale back their drilling plans the longer oil stays below that magic $70 to $80 range.

Exacerbating that is the credit crunch. Many independent producers in markets such as the North Sea have been relying on debt capital to fund their drilling projects. Without access to debt capital, these firms are being forced to scale back.

Although the effects aren’t immediate, the longer oil stays below the $70 to $80 range, the more likely we’ll see a retrenchment in exploration spending. And any decline in spending would soon show up in the form of falling oil production.

Bottom line: The current demand picture for oil is broadly negative while the supply picture remains relatively tight. Oil is likely to eventually resume its uptrend; however, you can count on a great deal of volatility as the market sorts through those opposing forces over the next six to nine months.

The picture for natural gas is more bullish near term. The primary downside driver of gas in recent months has not been demand but supply. Specifically, traders are worried that rapidly rising production from prolific unconventional gas fields would swamp demand and lead to a glut of gas.

There’s some evidence that US gas production has been rising rapidly this year; in fact, according to Energy Information Administration (EIA) statistics, US gas production is rising at the fastest pace in decades.

However, producers aren’t likely to drill themselves into oblivion. According to most producers, the key level to watch for natural gas is around $8.00 per million British thermal units (MMBtu). Below that level, many gas producers, especially small firms with a handful of wells, become unprofitable and must scale back their drilling plans.

And even bigger players such as US giant Chesapeake Energy (NYSE: CHK) get hit with gas at that level. Chesapeake, PetroHawk Energy (NYSE: HK) and several other major producers have announced plans to scale back on their drilling near term to avoid flooding the market with natural gas.

Any decline in drilling activity will have an outsized impact on supply. Wells in unconventional fields have a high decline rate; 30 to 50 percent production dropoffs in the first year are far from uncommon. As soon as producers slow their drilling activity, those rapid decline rates quickly whittle away at production volumes. The end result: tighter supplies.

On the demand front, gas demand is relatively stable and recession-resistant. Consumers are far more willing to cut back on their driving than to turn off their heat; winter heating is still a key source of demand for gas. And demand for electricity is also relatively insensitive to economic growth; gas used in power plants is expected to continue growing in coming years.

Bottom line: US gas producers appear to be taking the steps necessary to keep supplies under control. Meanwhile, gas demand is far less vulnerable to a weak economy that oil demand. This alls suggests a floor for gas prices near the recent lows.

One of the most common questions we’re asked is what effect the slide in commodities has on the prices of energy-related partnerships. The answer is simple: Most MLPs have little or no fundamental exposure to the price of oil or natural gas.

This is particularly true for midstream energy companies. “Upstream” refers to the actual production of oil, natural gas or other energy-related commodities, while “downstream” suggests refining and the actual marketing of oil and gas products to consumers and industrial users.

Midstream energy companies own the assets that connect producers with refiners and ultimate consumers. This includes pipelines, tankers, storage, terminal facilities and plants used to process natural gas.

It’s impossible to generalize completely, but the midstream business typically has little or no real exposure to commodity prices. For example, the most common asset owned by MLPs is oil and gas pipelines. Pipeline operators generally offer two basic types of transportation contract: firm or interruptible. The latter contract is sometimes called an “as available” contract.

Firm contracts usually consist of two types of fees, a demand (reservation) charge and a commodity charge. The former is a fee paid for reserving capacity on the pipeline; the demand charge must be paid whether the shipper actually puts gas through the line or chooses not to. Firm contracts also establish a particular firm’s maximum daily quantity (MDQ), the maximum amount a given shipper is allowed to ship per day. 

A commodity charge is an amount paid based on the volume of oil or gas transported on a given day. It is extremely important to note that this fee has absolutely nothing to do with the value of oil or natural gas shipped over the pipeline — the pipeline operator does not take possession of the commodities that are transported through its lines. The pipeline operator doesn’t care whether the natural gas that travels through its system trades at $6 per MMBtu or $20 per MMBtu. The only point that matters is how much gas is pushed through the pipe.

Interruptible contracts typically carry no demand charge. Rather, pipeline operators receive a commodity charge that’s based on supply and demand for service on a particular day. Just as with firm contracts, the fee pipeline operators charge has nothing to do with commodity prices; these are volume-based fees. 

As you might expect, pipeline capacity is allocated on a given day according to priority. Shippers with firm contracts are allocated their guaranteed capacity first; the only time this would likely be reduced would be because of pipeline damage or a weather-related issue such as a hurricane. After all firm contracts are satisfied, the pipeline owner can allocate capacity to firms wishing to ship gas under interruptible contracts.

One more point to note: There’s a difference between interstate and intrastate pipelines. Interstate pipes that cross state boundaries are subject to regulation from the Federal Energy Regulatory Commission (FERC). FERC regulators regulate the fees that an interstate pipeline operator can charge for its services; the process is fairly complex, but these fees are normally set to allow the operator to recover expenses incurred in building the pipeline and receive a reasonable utility-like return on their business. Fee determination also involves both the pipeline operator and major shippers on a given system.

Intrastate pipelines are regulated by individual states; for example, intrastate pipelines in Texas are regulated by the Texas Railroad Commission (TRC). The amount of regulation varies by state, but as general rule states impose less stringent regulation on rates and fees charged.

Most MLPs only build pipelines when they receive enough firm capacity commitments at acceptable rates to back up their construction costs. A pipeline operator will often propose a new pipe and then ask potential shippers for commitments. If it attracts enough interest and firm commitment, the MLP would go ahead with the pipe. If not, the project is canceled.

The bottom line: The pipeline transportation business offers steady, dependable cash flows that don’t change based on commodity prices. This is one of the steadiest, most cash flow positive businesses you’ll encounter. The midstream group’s resilient cash flows are evident from recent results.

Enterprise Products Partners’ key assets include onshore and offshore gas pipelines, a series of floating production platforms in the Gulf of Mexico, natural gas processing and fractionating facilities for removing NGLs from the gas stream and NGL pipelines.

In its recent quarterly release, Enterprise reported distributable cash flow of $316 million. But Enterprise’s Gulf Coast operations were negatively impacted by hurricanes Ike and Gustav to the tune of about $64 million in the quarter.

However, despite that one-off issue, Enterprise still covered its distribution 1.2 times; excluding hurricane-related charges coverage was closer to 1.5 times. This is considered a heavy distribution coverage ratio for an MLP and is particularly impressive in light of the fact that Enterprise has boosted its distributions by 6.6 percent over the past year.

Generally, all of Enterprise’s assets performed well in the quarter and the company doesn’t have much exposure to natural gas prices. Enterprise does have some slight exposure to commodity prices via gas processing margins; processing revenues tends to rise when oil is expensive relative to gas as has been the case over the past few quarters.

Gas processing is a simple business. Raw natural gas is composed primarily of methane but also includes other hydrocarbons such as propane and butane; these other products are broadly called natural gas liquids (NGL). NGLs must be separated from the gas stream before it can be put onto the pipeline network. In addition, the value of a barrel of NGLs tends to broadly track the value of a barrel of oil; when oil is expensive relative to gas, NGLs produced with gas are a valuable commodity.

In many cases, Enterprise receives a simple fee based on the volume of gas it processes. But the company still has a few processing contracts known as percent of proceeds contracts (POP). Under POP deals, Enterprise is compensated in full or in part by allowing the MLP to retain title to some of the NGLs it produces. Thus, when the value of NGLs rises, this can be a modest tailwind for Enterprise. But these effects are extremely modest by any measure.

Enterprise’s main growth angle–the building of new pipelines and other assets–is organic. And Enterprise has some impressive organic growth projects under way that will add to distributable cash flow in coming quarters.

The company’s two largest projects to be completed in the near term are the Meeker gas processing facility and the Sherman Extension pipeline. The former is a gas processing facility located in Colorado; gas processing capacity in the Rocky Mountains isn’t sufficient to meet demand because the region has seen strong gas production growth in recent years. This facility is in high demand and has deals in place with several major local gas producers.

The Sherman Extension pipeline is located in Texas near a prolific gas-producing unconventional play known as the Barnett Shale. This pipe is scheduled for completion ahead of schedule in the first quarter and is largely secured by transportation agreements with major producers.

Longer term, Enterprise has several other projects in the offing, including an offshore oil imports facility it’s building in conjunction with fellow Portfolio member TEPPCO Partners (NYSE: TPP).

We like the conservative tone of Enterprise’s recent conference call. Management hinted that it would seek to retain more cash rather than paying it out as distributions; this means a slower rate of growth, not a cut, in distributions.

Specifically, barring a major improvement in capital market conditions over the next 12 months, I expect Enterprise to grow its distributions by roughly 5.5 to 6.5 percent year-over-year in 2009. This move makes sense to me because by retaining more cash, Enterprise can afford to undertake highly attractive expansion projects without taking on more debt or issuing units. This is a flexibility that few MLPs can match. And with a sky-high coverage ratio, Enterprise’s distribution is absolutely secure even in the event the recession in the US is a lot longer and deeper than anyone is currently projecting.

Enterprise appears to have also scaled back its growth capital spending program. In recent years the company has been spending roughly $1.5 billion to $2 billion a year on growth projects; it’s committed to only $700 million to $800 million for 2009. The MLP is focusing only on the most profitable and assured prospects that it can finance without issuing more bonds or stock.

With $800 million in cash and available credit lines plus retained distributable cash, Enterprise has little real exposure to credit market conditions at least into early 2010. Due to the stock’s defensive characteristics, Enterprise offers a slightly lower-than-average yield of 8.5 to 9 percent. But its unblemished record of boosting distributions, attractive financing position and ongoing organic projects, Enterprise Products Partners is a buy.

Kinder Morgan Energy Partners has an impressive slate of assets including refined petroleum products pipelines, natural gas lines, crude oil terminals and gas processing facilities. Just as with most midstream operations, these are primarily fee-based businesses; most of Kinder’s pipelines and storage facilities are also backed by long-term capacity agreements under which shippers pay Kinder a demand charge whether or not they actually use their capacity.

Kinder Morgan Energy’s carbon dioxide (CO₂) business is basically a series of pipelines to transport CO₂ to mature oilfields where it’s used in enhanced oil recovery. Enhanced oil recovery is simply the process of injecting CO₂ into an old oilfield to help repressurize the field and produce more oil.

As part of this business, Kinder Morgan Energy owns a significant stake in two mature oilfields that are being produced using this method. This is the only part of Kinder’s business that has any leverage whatsoever to commodity prices. And the company’s CO₂ business makes up less than 9 percent of revenues. Even better, Kinder hedges its exposure to oil to all but eliminate any commodity exposure.

Like Enterprise, Kinder also relies heavily on organic expansion projects for growth. Two of its most promising organic growth deals are the Rockies Express (REX) and MidContinent Express Pipelines.

REX is a pipeline that is designed to carry gas from the prolific Rocky Mountain region eastward. Natural gas production in the Rockies has grown significantly in recent years but there is little local consumption; most of the core gas-producing region is sparsely populated.  At the same time, pipeline capacity to carry gas out of the Rockies to key consuming markets such as the East Coast is extremely limited.

What tends to happen is that natural gas gluts develop in the Rockies, particularly during the summer months. When that happens, local gas prices plummet. Currently natural gas at the Henry Hub in Louisiana trades at close to $7 per MMBtu compared to $3.40 per MMBtu at the Opal Hub in Wyoming. If you’re a producer in the Rockies, this is a big problem; you likely aren’t happy about selling your gas at half price.

REX partly solves this problem. Producers can producer gas in the Rockies and then ship it east, where prices are typically far more favorable. As you can imagine, the pipeline is extremely popular, and producers were quick to reserve capacity on REX. In fact, Kinder is already exploring plans to add capacity to the line; producers are willing to pay guaranteed fees to reserve that new capacity.

Kinder Morgan’s Midcontinent Express pipeline is a 50/50 joint venture between Kinder and fellow Portfolio holding Energy Transfer Partners (NYSE: ETP). This pipe extends from southeast Oklahoma across northern Texas, northern Louisiana, central Mississippi and into Alabama. This pipe passes adjacent to at least four major unconventional plays, including the Texas Barnett, Oklahoma Woodford, Arkansas Fayetteville and Louisiana Haynesville.

Thanks primarily to its slate of organic expansion projects Kinder recently announced it boosted its quarterly distribution to $1.02 per quarter, up a whopping 16 percent over the same quarter a year ago. Kinder is targeting a further increase to at least $1.04, and likely higher, for the fourth quarter. In the current quarter, Kinder covered its distribution about 1.07 times.

This distribution looks tight, but you have to consider the fact that many of Kinder’s key projects weren’t completed until late in the quarter. It didn’t get the full benefit of those revenues for the entire quarter. Looking at 2008 on a year-to-date basis, Kinder has generated nearly $100 million in excess distributable cash flow above and beyond what was actually paid in distributions. This is a comfortable cushion.

Kinder appears to have ample liquidity to fund growth projects it’s already committed to for 2009. And Kinder has decided to partner with other MLPs of a few of its more recently announced projects; by spreading the costs the firm reduces its need to raise capital.

However, the most important point to emerge from Kinder’s recent conference call was the firm support from its general partner, Knight Inc. Knight is controlled by the chairman and CEO of Kinder Morgan, Richard Kinder. Somewhat like Dan Duncan over at Enterprise, Kinder is not a man you see on CNBC everyday, but he’s definitely a legend in the energy business, and according to Forbes he’s the 130th-richest man in the world.

In an interesting twist, Kinder was once president of the infamous Enron. He left the firm in 1996 because he wasn’t on board with Ken Lay’s “asset-light” strategy. In other words, Kinder wants to own real cash-producing assets such as pipelines. At the time many pundits thought that was a dumb move; we don’t have to tell you how it worked out in the end.

At any rate, Kinder stated that he and Knight stand behind Kinder Morgan, and Knight has access to a credit line and cash reserves totaling between $750 million and $800 million. Knight stands ready to invest that cash as needed in equity or debt securities to support Kinder Morgan Energy Partner’s expansion projects. With a yield around 8 percent, Kinder Morgan Energy Partners rates a buy under 65.

Smaller but equally defensive is Sunoco Logistics Partners (NYSE: SXL). Suncoco Logistics owns a series of refined products pipelines and crude oil terminals. These are among the most stable businesses an MLP can own.

Refined products pipelines carry petroleum products such as gasoline and jet fuel; like all pipelines, revenues are based on volumes transported, not prices. Of course, the volume of refined products transported in and around the US has been falling in recent quarters due to the recession.

While you might assume that lower volumes means lower revenues, that’s not necessarily the case; Sunoco is actually increasing the tariffs it charges enough to offset any volume declines. This seems to be the case across much of the industry; most refined products pipeline companies reset their tariffs annually by an amount equal to inflation (measured by producer price inflation) plus an additional margin.

Sunoco is also seeing even stronger growth in its terminals segment. The company has some older contracts coming up for renewal; these contracts are seeing huge price increases as they’re renewed. And terminals are generally seeing high demand for ancillary services such as mixing ethanol and other additives to gasoline.

Sunoco has two major growth projects in the hopper at this time. The first is tank facilities and a pipeline to connect its existing Nederland terminal in Texas to the massive Motiva Port Arthur refinery. That refinery is undergoing an expansion, so this infrastructure is crucial.

The second is Sunoco Logistics’ acquisition of a refined products pipeline in Texas from integrated oil giant ExxonMobil. Not only will that that purchase add directly to cash flow but there are myriad opportunities for Sunoco to add tank capacity and other ancillary infrastructure around this asset.

But there are two main reasons we can see that Sunoco is a must-own MLP. First, the company ranks at the bottom of its industry group in terms of debt burden; it has a lot less exposure to weak credit markets than its peer group. In addition, Sunoco has $400 million in undrawn credit facilities and unrestricted cash. That compares favorably to its $125 million or so of growth and maintenance capital expenditure needs for 2008. Bottom line: Sunoco Logistics doesn’t need access to the capital markets this year or next.

Second, Sunoco has a long history of grinding out consistent distribution increases over time from its low-risk asset base. In the most recent quarter, Sunoco boosted distributions by 13.5 percent year-over-year. And management has reaffirmed its guidance to boost distributions by a further 10 percent in 2009 despite the weak credit market conditions.  Buy Sunoco Logistics.

We’re also adding a new midstream MLP to the Portfolio, Plains All-American Pipeline (NYSE: PAA).

Plains owns a network of crude oil and refined products pipelines as well as 23 million barrels of crude oil and refined products storage capacity. These are classic midstream assets backed up by fee-based revenues that depend solely on the volumes transported and stored.

Crude oil storage is a particularly attractive market right now. The reason has to do with what’s known as contango. Contango is a futures market term that refers to the difference between near-month and long-term futures prices. In other words, the current cost of crude oil is far lower than the price of crude oil for delivery early in 2009.

To quantify, the price of crude oil for immediate delivery is about $66 a barrel, while the price of crude for delivery about a year from today is closer to $78. This spread has been widening in recent months. This creates an incentive for companies to store crude; they can store the crude now and sell it via the futures market one year from now at that higher price. This sets up a sort of arbitrage situation that drives demand for storage.

Plains hasn’t yet reported third quarter results, but the company recently boosted its quarterly payout to 89.25 cents, up about 6.5 percent year-over-year. The firm also announced that, as of the end of the third quarter, it had $765 million in undrawn capacity on a credit facility that doesn’t expire until 2012. With a capital spending plan of around $250 million for 2009, that’s plenty of liquidity to fund projects without seeking new credit capacity of issuing new units.

A slow-but-steady performer with a solid yield of just under 9 percent, Plains All-American Pipeline rates a buy under 47.