Growth Portfolio holding Linn Energy LLC’s (NSDQ: LINE) second-quarter results fell short of expectations, prompting management to reduce its full-year forecast for distributable cash flow (DCF). The limited liability company (LLC) generated $0.70 per unit in DCF, which fell slightly short of the declared quarterly payout of $0.725 per unit. In contrast, Linn Energy covered its payout by 114 percent in the first quarter.

Despite these disappointing results, the firm grew its hydrocarbon output by 76 percent from a year ago, to 630 million cubic feet equivalent per day. Much of this upside stemmed from the integration of new acquisitions, though Linn Energy also posted solid production increases in core operating regions such as the Permian Basin and the Granite Wash.

Linn Energy’s efforts to improve drilling efficiency and the implementation of an innovative system for handling the water used in hydraulic fracturing, a production technique that unlocks hydrocarbons from low-permeability reservoir rocks, also reduced expenses from year-ago levels.

What drove the LLC’s disappointing second quarter? The price of natural gas liquids (NGL)–a group of heavier hydrocarbons whose price historically has tracked movements in the value of West Texas Intermediate crude oil–tumbled precipitously.

Source: Bloomberg

The barrel of mixed NGLs tracked in this graph consists of 36.5 percent ethane, 31.8 percent propane, 11.2 percent normal butane, 6.2 percent iso-butane and 14.3 percent natural gasoline, all of which are delivered at the hub in Mont Belvieu, Texas. As you can see, NGL and oil prices surged in 2007 and early 2008, collapsed in 2008 and early 2009, and rose in tandem from mid-2009 through to 2011.

From the beginning of 2006 to mid-2011, a barrel of NGLs usually fetched roughly 60 percent of the price of a barrel of WTI crude oil. But this long-standing price relationship has deteriorated over the past eight months; a mixed barrel of NGLs recently bottomed at about 40 percent of the benchmark oil price for North America.

Source: Bloomberg

When you compare the price of a mixed barrel of NGLs to the market value of Brent crude oil, the differential is even greater, as this international oil benchmark has commanded a significant premium to WTI crude oil over the past two years.

Ultra-depressed US natural gas prices, the decline in NGL prices and the discounted price of WTI crude oil relative to international reference points stem, in part, from rising production of all three commodities from the nation’s prolific shale oil and gas plays.

But there’s an old saw in the energy business that says it’s harder to grow oil and liquids output than natural-gas production. The shale oil and has revolution hasn’t invalidated this maxim. Although US oil output has increased for the first time in more than 30 years, this uptick in pales in comparison to the surge in natural-gas production that has overwhelmed domestic demand.

The supply-demand balance in the NGL market lies between the extremes of the glut of natural gas in the domestic market and the substantial supply shortfall that forces the US to make up the difference by importing significant quantities of oil.

Domestic NGL production eclipsed 2 million barrels per day in 2010–a record high–and averaged 2.38 million barrels per day in May 2012, a 7 percent increase from year-ago levels.

Source: Energy Information Administration

At the same time, the newfound abundance of ethane and propane has revivified the domestic petrochemical industry, giving chemical manufacturers a dramatic cost advantage over producers in Asia and the Middle East that rely on naphtha and other oil derivatives for feedstock.

Over the past decade, multinational chemical producers such as Dow Chemical (NYSE: DOW) have gradually shifted their production base from the US to Asia (to build a presence in growing demand centers) and the Middle East (to take advantage of lower feedstock costs).

Last year, this trend reversed course. A number of major petrochemical producers announced plans to restart shuttered crackers or construct world-class plants to take advantage of favorable pricing on ethane and propane.

For example, Dow Chemical–the world’s second-largest chemical outfit–announced plans to restart its ethane cracker at its St. Charles complex, upgrade one plant in Louisiana and another in Texas to enable them to accept ethane feedstock and build a new ethylene production plant on the Gulf Coast in 2017. The firm aims to improve its ethane cracking capabilities by 20 percent to 30 percent to take advantage of the superior economics offered by the NGL.

And Royal Dutch Shell (LSE: RDSA, NYSE: RDS: A) in June 2011 announced that it would build a world-scale ethylene plant in Appalachia that would source its feedstock from the Marcellus Shale. Meanwhile, Chevron Phillips Chemical–a joint venture between Chevron Corp (NYSE: CVX) and ConocoPhillips (NYSE: COP)–plans to build a major ethane cracker and ethylene derivatives facility in the Texas Gulf Coast region.

Equally important, the US has some capacity to export propane and NGL-derived products. Both Enterprise Products Partners LP (NYSE: EPD) and Targa Resources Partners LP (NYSE: NGLS) own or are in the process of building propane export capacity. However, the nation’s existing export capacity is maxed out.

The recent price decline has hit lighter NGLs, especially ethane, which recently slipped to a low of roughly $12 per barrel from more than $30 per barrel at the end of 2011. Although the prices of propane and butane have also tumbled considerably from their 2012 highs, producers can still generate a solid return on these NGLs.

Source: Bloomberg

The most conservatively run of the upstream MLPs, Linn Energy hedges all its expected oil and gas production for years in the future, limiting its exposure to the vagaries of the commodities market. However, this extensive hedge book, which insulated the firm from the collapse in commodity prices in late 2008 and early 2009, isn’t as effective protecting the firm’s cash flow against fluctuations in NGL prices.

Producers traditionally have hedged NGL production with oil futures, reflecting the long-standing relationship between the prices of these two commodities. Unfortunately, NGL prices have declined to a much greater extent than the price of WTI crude oil; in this environment, a short position in crude oil failed to fully protect producers from plummeting NGL prices.

Although producers can hedge NGL prices, the market for these futures lacks sufficient liquidity. Clay Jeansomme, Linn Energy’s vice president of investor relations, addressed this challenge during a conference call to discuss the LLC’s second-quarter results:

[I]f you look back and say, okay, when we looked at hedging it [Linn Energy’s NGLs exposure] it’s backwardated by 30, 40 percent, how bearish do you want to be? But having said that, you would have endured that king of lowered pricing for six months and so you saw the lower pricing that we are seeing today. So, probably nets up to about the same. It just didn’t look that compelling honestly, and even looking back it’s still questionable as to whether it’s compelling.

So, until there is a longer-dated, less-backwardated NGL hedge market–and we look at it, trust me, we will look at it every day, because if we had the ability to hedge NGL for 100 percent and then they would be consistent with everything else we do at LINN–we would be all over that. But the economics has just never looked compelling at the times we’ve looked at it. So we’ll keep looking but I don’t regret it really at this point.

When a producer hedges its output, the firm sells that commodity forward. That is, if an upstream operator expects to flow 1,000 barrels of oil per day in May 2013, the firm’s traders would sell May 2013 futures contracts for 31,000 barrels of oil (31 days in May times 1,000 barrels of oil per day). At present, the contract for WTI crude oil to be delivered in May 2013 sells for about $90 per barrel, while the current quote in the spot market is about $88 per barrel. In this case, the hedge locks in a guaranteed price on this future production that exceeds prevailing prices.

The differentials between the current price of natural gas and futures contracts are even more favorable: Whereas the fuel fetches $3.25 per million British thermal units (mmBtu) in the spot market, natural gas to be delivered in July 2013 goes for $3.65 per mmBtu. Producers can lock in natural gas prices of more than $4 per mmBtu on futures contracts for December 2013. In this situation, the market is in a state of contango–that is, futures contracts trade at a premium to spot prices and near-term futures contracts.

The NGL market, in contrast, finds itself in steep backwardation, where future prices are significantly lower than prevailing spot prices. In other words, a producer seeking to hedge its NGL prices would lock in a price on future production that’s 30 percent to 40 percent lower than the current quote.

The lack of an efficient means of hedging NGL output, coupled with a sharp drop in the prices of these commodities, explains why Linn Energy’s DCF failed to cover its quarterly distribution. Excluding the effect of weak NGL prices, the LLC would have generated enough cash flow to cover 115 percent of its quarterly payout.

Even if NGL prices remain at depressed levels, management expects the publicly traded partnership’s distribution coverage to improve to 120 percent in 2013. This forecast could ultimately prove conservative; butane prices have climbed about 18 percent since their June nadir, propane prices have recovered by more than 30 percent and ethane prices have rebounded by almost 40 percent.

Management’s bullish outlook reflects three upside drivers: the integration of new acquisitions, a focus on growing oil production organically and a shift in NGL volumes from Conway, Kan., to Mont Belvieu, Texas.

Acquiring Growth

Thus far in 2012, Linn Energy has announced $2.8 billion in acquisitions and joint ventures–almost as much as it completed in 2010 and 2011, combined. Management also disclosed that, through the end of June, the firm had bid on 11 deals worth about $6 billion; in 2011 the LLC had submitted offers on 31 transactions worth $7.5 billion.

This year, the firm has announced two blockbuster deals with BP (LSE: BP, NYSE: BP) for natural gas-producing properties: the $1.2 billion acquisition of acreage in the Hugoton Basin and the $1.025 billion purchase of properties in Wyoming’s Jonah Field. Natural gas accounts for about 73 percent of production from the Jonah Field and 63 percent of output from Linn Energy’s new acreage in the Hugoton Basin.

Although the price of natural gas remains depressed in North America, Linn Energy acquired this acreage at bargain valuations that guarantee a solid return on investment, paying about $1.65 per thousand cubic feet of natural gas equivalent in the Hugoton Basin and $1.40 per thousand cubic feet of natural gas equivalent in the Jonah Field.

As usual, Linn Energy has hedged all expected natural-gas production from these properties through 2017, locking in solid profit margins on this future output.

Once these newly acquired assets contribute to Linn Energy’s results for a full quarter, the LLC’s production mix will shift toward gas and its DCF will receive a welcome boost.

We wouldn’t be surprised if Linn Energy were to ink other low-risk acquisitions in the back half of the year, especially as producers seek to monetize older natural gas-producing assets drilling activity in unconventional plays. During a July 26 conference call, management noted that the size and quality of acquisition opportunities had increased this year. Recent moves to enlarge its credit facility by $1 billion and raise funds through the pending initial public offering (IPO) of Linn Co LLC (NSDQ: LNCO), covered in the June 28 Flash Alert, Good Deals.

We would expect any forthcoming deals to be immediately accretive to DCF.

Oil Bias

Linn Energy’s operations in the Granite Wash, a liquids-rich play in Oklahoma and the Texas Panhandle, accounts for much of the firm’s exposure to NGL prices. Natural gas represents for about 35 percent of the field’s production, oil makes up 30 percent and NGLs account for 35 percent. To worsen matters, ethane accounts for 45 percent of the natural gas liquids that Linn Energy extracts from the field.

Although some producers elect to leave ethane in the natural-gas stream when processing costs exceed the value of the hydrocarbons, Linn Energy hasn’t pursued this practice because the value of the other NGLs in the gas stream offsets weak ethane prices.

Instead, Linn Energy has opted to focus on the Hogshooter, a shallower formation in the same region which yields a superior production mix that’s 72 percent crude oil, 14 percent natural gas and 14 percent NGLs. The firm has reassigned the eight rigs that had operated in the liquids-rich Granite Wash to target the Hogshooter, where it expects to sink another 20 wells in the back half of the year. To date, the LLC has drilled three Hogshooter wells in the Texas Panhandle that have yielded initial production rates of about 2,500 barrels of oil equivalent per day and yielded a total of 285,000 barrels of oil equivalent over the first 90 days.

Meanwhile, the company continues to evaluate the potential of the Hogshooter formation in its Oklahoma acreage, a process that could further expand its inventory of drilling locations.

Management’s expectations for the drilling program in the Hogshooter call for an initial production rate of 1,700 barrels of oil equivalent per day–about two-thirds the rate that the firm achieved on its first three wells.

Delivery Point

Some of the shortfall in Linn Energy’s second-quarter DCF also reflects the destination of the NGLs produced from its wells in the Granite Wash. Robust drilling activity in the Mid-Continent region has led to an oversupply of NGLs at the hub in Conway, Kan., depressing prices relative to the delivery point in Mont Belvieu, Texas. Propane, for example, fetches about $25 per barrel at Conway, compared to $38 per barrel at Mont Belvieu.

Linn Energy’s existing processing contract expires at year-end, and the firm has invested considerable sums on infrastructure and pipeline interconnections to support drilling its operations in the Granite Wash. Without providing too much detail, management indicated that the firm should be able to redirect a significant portion of its NGL volumes to Mont Belvieu, a development that would boost price realizations.

The Verdict

Based on these factors, Linn Energy’s management team expects to generate enough DCF to cover its annual distribution by 110 percent in 2012 and 120 percent in 2013. This guidance, which excludes the benefits of a recovery in NGL prices or any additional acquisitions, will likely prove overly conservative.

Such a shortfall is usually a red flag in the MLP space and is punished by the market. But Kinder Morgan Energy Partners had already set expectations for a DCF shortfall in the second and third quarters of 2012 because of lumpiness in realized cash flows. Strong first-quarter results enabled the publicly traded partnership to cover the corresponding distribution by 114 percent, while its cash flow in the first six months of the year managed to cover the cumulative payout to this point.

That being said, second-quarter results were a touch weaker than management had expected, largely because of weaker NGL prices and a slower-than-expected ramp up in volumes on some certain pipelines.

When you exclude depreciation and other noncash accounting charges, products pipelines segment accounted for about 17 percent of Kinder Morgan Energy Partners’ earnings. This division includes more than 8,000 miles of refined-product pipelines and has generated results that are close to management’s guidance on a year-to-date basis. But this operating segment’s DCF will likely fail to meet the firm’s full-year estimate.

Refined-product volumes declined by 0.9 percent from the second quarter of 2011, reflecting weakening US demand for gasoline and diesel fuel. A lower tariff on its Pacific pipeline system didn’t help matters.

The MLP’s natural gas pipelines segment accounted for roughly a quarter of the firm’s adjusted earnings in the second quarter and should beat management’s expectations for the full year, though its first-half results were slightly off the pace.

The acquisition of the remaining 50 percent interest in the KinderHawk system in Louisiana’s Haynesville Shale, rising throughput on its pipelines in Arkansas’ Fayetteville Shale and an upsurge in volumes on its gathering system in the Eagle Ford Shale boosted the segment’s adjusted earnings by 25 percent from year-ago levels.

Nevertheless, this growth has falln short of expectations for two reasons: disappointing volume growth on the KinderHawk system, a product of reduced drilling activity in this gas-focused basin, and in the Eagle Ford Shale, where robust drilling activity has led to equipment shortages and delays bringing production onstream.

Fortunately, the take-or-pay contracts backing the aforementioned pipeline systems guarantee a minimum level of cash flow regardless of whether customers use their allotted capacity.

Drop-down transactions from Kinder Morgan Inc. (NYSE: KMI), the MLP’s general partner, should more than make up for these deficiencies. In a drop-down transaction, the general partner sells assets to the MLP at prices that are usually immediately accretive to cash flow.

Kinder Morgan Inc. expects to sell Tennessee Gas Pipeline and a portion of El Paso Natural Gas to Kinder Morgan Energy Partners in the third quarter. Cash flows from these acquisitions will be somewhat offset by divestitures required by the Federal Trade Commission (FTC), but, on the whole, these transactions will be accretive to DCF.

The CO2 (carbon dioxide) segment accounted for about one third of Kinder Morgan Energy Partners’ adjusted earnings. This division supplies CO2 to third-party producers and the firm’s own mature oil fields, where the gas is pumped into the reservoir to enhance recovery rates. The firm hedges its exposure to commodity prices.

Although management expects production from its oil and gas fields to meet expectations, the firm’s exposure to NGL prices will reduce full-year cash flow by about 5 percent.

The terminals segment accounted for about 19 percent of cash flows in the second quarter and should beat management’s full-year guidance because the oversupplied domestic coal market has led to an upsurge in shipments from Kinder Morgan Energy Partners’ four export facilities. To take advantage of this opportunity, the MLP is in the process of expanding three of these terminals. In each case, the additional export capacity is backed by long-term commitments.

Kinder Morgan Canada consists of 2,500 miles of pipeline stretching from Alberta and British Columbia into the Central and Pacific Northwest portions of the US. This relatively small business segment should slightly outpace management’s full-year budget.

All told, management expects the firm expects to generate enough cash flow to cover the full-year distribution of $4.98 per unit. Kinder Morgan Energy Partners also reiterated its long-term goal of growing its distribution at an average annual rate of 7 percent from 2011 to 2015. Drop-down transactions from Kinder Morgan Inc.’s acquisition of El Paso Corp will be critical to achieving this target. Buy Kinder Morgan Energy Partners LP up to 82.

Fellow Conservative Portfolio holding El Paso Pipeline Partners LP (NYSE: EPB) joined the family after Kinder Morgan Inc. acquired its general partner in the blockbuster purchase of El Paso Corp. Critics fretted that El Paso Pipeline Partners’ new general partner would favor Kinder Morgan Energy Partners, though this fear hasn’t come to fruition.

In the second quarter, El Paso Pipeline Partners generated about $0.65 in DCF per unit, covering its distribution of $0.55 per unit by a comfortable margin of 118 percent. Meanwhile, Kinder Morgan Inc. has lived up to its word, dropping down the Cheyenne Plains Gas Pipeline and the Colorado Interstate gas pipeline to El Paso Pipeline Partners.

Thanks to these deals, management expects the MLP to disburse $2.25 per unit to investors. Future transactions should enable the firm to grow its payout at an average annualized rate of 9 percent between 2011 to 2015. Buy El Paso Energy Partners LP up to 38.

Aggressive Portfolio holding Penn Virginia Resource Partners LP (NYSE: PVR), which on May 17 completed the $1 billion purchase of Chief Gathering LLC from the privately held Chief E&D Holdings LP, posted a disappointing second quarter.

Despite the acquisition of additional gathering and processing assets in the Marcellus Shale, the MLP’s DCF tumbled to $26.1 million ($0.291 per unit), down 30.6 percent from a year ago. This decline ensured that cash flow covered only 60 percent of Penn Virginia Resource Partners’ quarterly distribution.

These lackluster results prompted management to revise its forecast for full-year DCF to between $120 and $130 million from $160 million to $180 million. In a show of strength, Penn Virginia Resource Partners also hiked its quarterly distribution to $0.53 per unit, a 1.9 percent increase from the prior quarter. Assuming that the MLP maintains the current quarterly payout through year-end, this guidance implies full-year distribution coverage of 71.9 percent to 78.6 percent.

Management attributed this shortfall to three factors: weaker coal volumes and prices in North America (about two-thirds of the reduction in guidance), a decline in the price of NGLs and the MLP’s migration to lower-margin, fee-based contracts at its midstream operations in the Mid-Continent region.

Coal Conundrum

Penn Virginia Resource Partners LP owns and manages 804 million tons of coal reserves primarily in Central Appalachia, though the firm’s portfolio also includes producing properties in Northern Appalachia, the Illinois Basin and New Mexico.

About 89 percent of the coal that Penn Virginia Resource Partners’ properties produce is steam coal, the kind used in power plants. But the company’s mines in Central Appalachia contain high-grade metallurgical coal, the varietal used in steel production.

Penn Virginia Resource Partners doesn’t mine coal; instead, the MLP leases coal-producing properties to mining firms such as Peabody Energy Corp (NYSE: BTU) in exchange for royalties. These 10- to 15-year agreements usually involve a guaranteed minimum plus a fee based on the value of the coal mined on the partnership’s properties.

Although these agreements somewhat buffer Penn Virginia Resource Partners’ against weakness in the coal market, declining sales volumes and prices weighed heavily on the MLP’s second-quarter results.

US coal producers have felt the burn after the no-show winter of 2011-12, which elevated electric utilities’ inventories of coal and further depressed the price of natural gas, making the relatively clean-burning fuel more competitive. With the price of natural gas plumbing record lows and offering superior economics to coal, utilities with the flexibility to take coal-fired capacity offline and ramp up gas-fired plants have eagerly made the switch.

The Energy Information Administration currently projects that the US electric power industry’s coal consumption will tumble 14.3 percent in 2012, to 796 million short tons. Electric utilities in 2011 accounted for about 92 percent of domestic coal demand.

Fuel switching has weighed heavily on coal producers’ earnings, especially those with elevated production expenses or outsized exposure to Central Appalachia, a region where compliance costs have increased and incremental production growth is hard to come by because of depleted seams. At current commodity prices, producing coal in this region is uneconomic for many operators.

To worsen matters, reduced heating demand during the 2011-12 winter has elevated many utilities’ coal inventories, prompting some power companies to sell excess supplies in the spot market (further depressing prices) or push to delay contracted deliveries.

But investors shouldn’t assume that the recent bout of fuel-switching marks the end of King Coal. Natural gas prices eventually will rise to levels that make thermal coal more attractive to electric utilities. At that point, price-related fuel switching will reverse course.

Central Appalachian coal becomes more competitive in the Southeast when natural gas exceeds $3.50 per million British thermal units (mmBtu) to $4.00 per mmBtu, while utilities have an economic incentive to revert to coal from the Powder River Basin when natural gas tops $3.00 per mmBtu.

Penn Virginia Resource Partners’ CEO William Shea summed up the coal industry’s response to these headwinds in a conference call to discuss second-quarter results: “reduced shifts, extended vacations, idling of facilities and operator contract terminations,” all of which seek to align supply with demand. The aforementioned actions are all voluntary, but bankruptcy should also appear on the list. Patriot Coal Corp (OTC: PCXCQ) on July 10 filed for bankruptcy protection, sunk by a major customer default and plummeting cash flow.  

The MLP’s management team likewise warned that US steam coal prices were unlikely to recover in the back half of the year or in early 2013, as competitive natural gas prices and elevated inventories have prompted utilities to push back scheduled deliveries until next year. Although the summer heat has provided some relief in this regard, coal producers are hoping that a cold winter will help to alleviate the supply overhang.

These trends weighed heavily on results in Penn Virginia Resource Partners’ coal and natural resource management division, which still accounted for 46.7 percent of the firm’s adjusted earnings before income, taxes, depreciation and amortization (EBITDA) and meaningfully impacts the firm’s overall results.

In the second quarter, this operating segment generated adjusted EBITDA of $26.7 million, down 37 percent from year-ago levels. Management attributed the majority of this weakness to a decline in coal-royalty tons, which tumbled 22.7 percent from 12 months ago, to 7.8 million tons. Meanwhile, the plummeting price of steam coal also reduced the firm’s second-quarter coal royalty revenue to $3.76 per ton, compared to $4.40 per ton in the second quarter of 2011.

On the plus side, management disclosed that the firm’s largest lessee, Peabody Energy, has largely maintained its output, which is destined for the Southwest, a niche market where coal demand has remained relatively stable. At the same time, management disclosed that Patriot Coal plans to continue mining its leased properties in Central Appalachia, though some output reductions are likely.

Mid-Continent Challenges

Penn Virginia Resource Partners’ midstream operations in the Mid-Continent region, which posted a 27.4 percent decline in adjusted EBITDA during the second quarter, also faced their fair share of headwinds.

Although throughput on the MLP’s gathering and processing system surged to 453 million cubic feet per day from 422 million cubic feet per day a year ago, this increase in volumes failed to offset the massive decline in NGL prices at the hub in Conway, Kan.–a phenomenon we discussed at length in our analysis of Linn Energy’s second-quarter conference call.

Penn Virginia Resource Partners also has some exposure to NGL prices in this region, as keep-whole agreements–contracts in which the processor retain the NGLs as compensation for its services–account for 15 percent to 20 percent of throughput in a given quarter. Meanwhile, percent-of-proceeds contracts account for about 60 percent of processed volumes. In these deals, the processor receives a predetermined percentage of the proceeds from the sale of the natural gas and NGLs.

Management also noted that in mid-May–the nadir for NGL prices–some producers had opted to keep ethane in the natural gas stream rather than paying processors to remove this hydrocarbon for sale.

Looking Ahead

Despite this undeniably disappointing second quarter, Penn Virginia Partners’ unit price has held up reasonably well, largely because management indicated that the firm would cover its full-year distribution by 110 percent in 2013, assuming it meets the midpoint of its forecast for Adjusted EBITDA.

With volumes and pricing in the coal segment likely to remain under pressure in 2013, management has pinned its hopes on the firm’s eastern midstream segment, which accounted for 31 percent of total adjusted EBITDA in the second quarter.

Management has noted that the expansion of existing infrastructure in the Marcellus Shale and the integration of assets acquired from Chief E&D holdings will increase the percentage of fee-based contracts to 80 percent of nameplate capacity.

This transition from a coal-focused MLP to one that generates the majority of its cash flow from midstream infrastructure was never going to proceed without a few hitches. That being said, we remain bullish on the company’s long-term growth prospects, though investors may want to wait for a pullback to build their position. Buy Penn Virginia Resource Partners LP up to 29.