The unseasonably warm winter of 2011-12 has sent already depressed natural gas prices spiraling even lower–and the outlook for the commodity is unlikely to improve significantly over the next 12 to 24 months.

Consumption of natural gas usually peaks during the winter, when residential and commercial heating demand experiences its seasonal upsurge. Heating demand is the primary reason that the volume of natural gas in storage tends to rise from April to mid-November and fall from mid-November to the end of March.

Source: National Oceanic and Atmospheric Administration

This graph tracks anomalous weather conditions from January 2012 to the end of March 2012 by comparing recent temperatures to the average between 1971 and 2000. The US and Canada enjoyed one of the warmest winters on record, with temperatures averaging 5 degrees to 6 degrees Celsius (9 degrees to 11 degrees Fahrenheit) above normal. This unusually warm weather and lower-than-normal precipitation likely boosted the economy in the US and Canada above seasonal norms.

A heating degree day (HDD) is a way to measure how much heat is required to bring a building to a comfortable temperature. To calculate HDDs, you subtract the average temperature each day from a base value of 65 degrees Fahrenheit. In other words, if the average temperature on a certain day were 40 degrees, that day would be worth 25 heating degree days (65 minus 40). The more HDDs, the colder the weather and the higher heating demand.

Source: Energy Information Administration

This graph depicts population-weighted HDDs at a national level. Between December and February 2012, the US experienced 13 percent to 18 percent fewer heating degree days than usual. HDDs were about 36 percent below average in March 2012, the warmest March on record.

Investors should remember that weather events are transitory and unpredictable; the cold winters of 2009-10 and 2010-11, for example, stimulated demand for natural gas.

Although the extraordinarily warm winter exacerbated the weakness in natural gas prices, excess production remains the biggest challenge.

The rapid development of unconventional US natural gas and oil shale fields such as the Haynesville Shale in Louisiana, the Eagle Ford in Texas and the Marcellus Shale in Appalachia has led to a surge in US natural gas production.

Source: Energy Information Administration

Chesapeake Energy Corp (NYSE: CHK) and a number of other major producers have announced plans to reduce drilling activity targeting natural gas; with natural gas fetching less than $2 per million British thermal units, even the fields with low production costs are uneconomic.

The number of rigs actively drilling for natural gas in the US has tumbled from more than 900 units in December 2012 to only 613 rigs. In fact, the gas-directed rig count is lower today than at the height of the 2008-09 financial crisis. At one point in 2008, more than 1,600 drilling rigs targeted natural gas.

Subscribers often ask whether the decline in natural gas-directed drilling activity will relieve the supply glut. In the near to intermediate term, these moves won’t stem production and allow the price of natural gas to recover.

Although the great migration of drilling rigs from the Haynesville Shale and other dry-gas fields has continued apace for several months, several offsetting factors have ensured that US marketed gas production remains near record levels.

For one, producers can now sink more wells and produce more gas using fewer rigs. For example, in 2007, it took Southwestern Energy (NYSE: SWN) about 17 days to drill a well in Arkansas’ Fayetteville Shale, compared to about 12 days in 2010 and eight days in 2011. In other words, the company can drill roughly the same number of wells using half as many rigs.

In addition, Southwestern Energy has increased the efficiency of its operations by drilling longer laterals, or the horizontal portion of the well. Over the past several years, US producers have found that increasing the number of fracturing stages in a horizontal well can also enhance output. In some shale plays, producers have more than 40 hydraulic fracturing sites on a single lateral. Hydraulic fracturing is a process whereby producers pump a liquid into a shale reservoir under such tremendous pressure that it cracks the reservoir rock.

By drilling longer laterals and adding fracturing stages, producers can generate higher initial production rates and increase the total amount of hydrocarbons recovered from each well. All these technological and methodological advances add up to higher production from fewer wells.

Source: Energy Information Administration

This graph depicts the number of newly drilled exploratory and developmental wells targeting natural gas. Although the US gas-directed rig count dropped to 800 rigs by the end of January from 1,000 in mid-2010, the number of wells drilled hasn’t changed measurably–a sure sign that producers are drilling more wells with fewer rigs.

According to the US Energy Information Administration (EIA), the 4,219 domestic oil and gas wells that producers sank in January 2012 sported a mean length of 6,809. A decade ago, producers drilled 2,446 wells that averaged 5,440 feet. Longer wells expose more of the productive regions in a formation and translate into higher production rates.

Meanwhile, the US oil-directed rig count has soared almost sevenfold since the mid-2009, to 1,328 rigs. In January 2012, producers drilled 2,324 domestic oil wells–the largest monthly total since March 1986.

Source: Bloomberg, Energy Information Administration

But these wells often produce volumes of natural gas and natural gas liquids (NGL), a group of heavier hydrocarbons that includes ethane, propane and butane. The Bakken Shale in North Dakota and Montana and the Permian Basin in west Texas contain significant quantities of associated natural gas. Gas-directed drilling activity continues to wane, but production of this commodity from oil wells continues to increase as operators shift their focus to liquids-rich shale plays.

State-level data on the volume of natural gas produced from wells targeting gas and the volume flowed from oil wells corroborates this theory, even though the most recent EIA data is from more than a year ago.

Source: Energy Information Administration

Most drilling activity in North Dakota targets the oil-rich Bakken Shale formation; oil production in the state has soared almost fivefold in the past half-decade. Natural gas production from oil wells in North Dakota increased by 53 percent between December 2008 and December 2010. As oil-directed drilling activity in the state has picked up significantly since late 2010, the production of associated gas has likely continued to climb.

The same trends are apparent in Texas. Although operators in the Permian Basin and parts of the Eagle Ford Shale target crude oil, gas production from Texas’ oil wells jumped by almost one-quarter in the two years ended Dec. 31, 2010.  

Robust production of natural gas, coupled with weather-weakened demand this winter, has pushed seasonal inventories of the energy commodity to record highs.

Source: Energy Information Administration

This graph tracks the volume of US natural gas in storage as a percentage of the five-year seasonal average. US gas inventories have generally remained elevated over the past two years, but the 2011-12 winter that never was sent storage levels surging to more than 50 percent above the seasonal average.

The US could reach peak storage capacity between now and next fall, forcing producers to shut-in their wells to rebalance the supply side of the equation.

In the near term, an unusually cold 2012-12 winter would help alleviate some of the pressure on US natural gas prices and perhaps allow the beaten-down commodity to rally to $3 per million British thermal units. Other upside catalysts are years away.

As a closed market with virtually no capacity to export liquefied natural gas (LNG), US producers lack a critical release valve that could enable them to take advantage of higher prices in Europe and Asia. A number of operators have announced plans to build LNG export facilities, but these terminals are unlikely to come onstream until at least mid-decade.

At the same time, depressed natural gas prices will continue to encourage electric utilities and manufacturers to expand their use of this feedstock. But these new generation facilities won’t be built overnight.

In this environment, we prefer well-capitalized names whose production mix is weighted toward oil and natural gas liquids, hydrocarbons that offer superior wellhead economics. At the same time, Chesapeake Energy Corp and other US independents will continue to monetize gas-focused acreage to support the migration toward liquids-rich plays.

Bottom line: The best way for investors to profit from natural gas is to focus on names that are scooping up high-quality gas-focused acreage at valuations that guarantee a solid rate of return even in the current environment.

Around the Portfolios

Quarterly earnings season is winding down. Here are the remaining release dates for our Portfolio holdings. Asterisks indicate that the date is estimated.

Growth Portfolio

Mid-Con Energy Partners LP (NSDQ: MCEP)–06/06/12*
Petrobras (NYSE: PBR A)–05/14/12*

Conservative Portfolio

Teekay LNG Partners LP (NYSE: TGP)–05/18/12

Aggressive Portfolio

Delta Air Lines (NYSE: DAL), the world’s second-largest air carrier, raised eyebrows on April 30, when management confirmed speculation and announced that the airline had inked a deal to purchase the Philadelphia-area Trainer refinery from Phillips 66 (NYSE: PSX).

The landmark deal marks the first time an airline has acquired a refinery. Delta Air Lines will pay $180 million for the downstream facility and associated pipeline and transportation assets, while Pennsylvania will kick in $30 million in assistance to ensure that the idled facility isn’t permanently closed. An additional $100 million in capital expenditures will enable the airline to maximize the refinery’s jet fuel production.

In a press release, Delta Air Lines’ CEO Richard Anderson highlighted the rationale behind the acquisition: “This modest investment, the equivalent of the list price of a new wide-body aircraft, will allow Delta to reduce its fuel expense by $300 million annually and ensure jet fuel availability in the Northeast.”

Quick-witted critics have panned the deal as a marriage between two money-losing concerns. Aggressive hedging hasn’t prevented rising fuel costs, which consumed about 35 percent of the major North American airlines’ 2011 revenue, from being a constant threat to the industry’s profit margins.

Meanwhile, integrated oil companies have sought to rationalize their downstream (i.e., refining and marketing) operations, divesting less-profitable refineries in the US in favor of facilities in the Middle East and Asian emerging markets, two regions that offer superior margins and growth prospects.

• BP (LSE: BP, NYSE: BP) in early 2011 announced plans to roughly halve its US refining capacity and has placed its Texas City and Carson, Calif. on the sales block. The company expects to complete these sales by the end of 2012, reducing its US refinery operations by 50 percent.
  
  
• Chevron Corp (NYSE: CVX) is in the midst of a three-year plan to rationalize its downstream operations. Last year, Chevron announced the sale of its Pembroke refinery and associated marketing assets in the UK and Ireland.

• ConocoPhillips (NYSE: COP) spun off its refinery and marketing assets as Phillips 66. The company plans to reduce its downstream exposure to 15 to 20 percent of overall revenue from 20 to 25 percent of revenue.

• Marathon Oil Corp (NYSE: MRO) in 2011 spun off its downstream operations as Marathon Petroleum Corp (NYSE: MPC).
  
  
• Royal Dutch Shell (LSE: RDSA, NYSE: RDS.A, RDS.B) has been restructuring its downstream operations since 2009 to divest smaller facilities and focus on Asia-Pacific and other markets with high growth potential. By 2012, management expects to reduce its downstream portfolio by a further 700,000 barrels per day.
  
  
• Total (Paris: FP, NYSE: TOT) plans to lower its gasoline output by 60 percent and has placed its UK Lindsey refinery, which accounts for 20 percent of its overall capacity, on the sales block.

Independent US refiners have also moved to reduce capacity, selling or closing smaller (and therefore less-efficient) plants on the East Coast–a highly competitive region that lacks access to cheaper, domestically produced crude oil from the Bakken Shale and other unconventional plays.

The majority of oil refined at East Coast facilities arrives via tanker from Nigeria, Angola, Algeria, the North Sea and other international locations. Check out this graph tracking the prices of West Texas Intermediate crude oil, the Bloomberg Bakken (Clearbrook, Minn.) crude oil spot price, and Brent crude oil, which is an international benchmark.   

Source: Bloomberg

In light of these challenges, Valero Energy Corp (NYSE: VLO), the largest US independent, last year sold its Delaware City and Paulsboro, N.J. refineries. Meanwhile, Sunoco (NYSE: SUN) in 2009 shuttered its Eagle Point refinery in Westville, N.J. The company last year moved to exit its legacy refining operations on the East Coast, shuttering a Pennsylvania facility capable of processing 175,000 barrels per day and entering negotiations to shift operation of another refinery in Philadelphia to the Carlyle Group. If this joint venture falls through, Sunoco would idle this facility by August 2012.

At first blush, the factors motivating Delta Air Lines’ purchase of the Trainer refinery makes a great deal of strategic sense for both sides involved. Phillips 66 monetizes a money-losing asset, while the air carrier’s acquisition of the refinery potentially lowers the company’s fuel expense by $300 million and could provide 80 percent of the company’s jet fuel needs. In 2011 Delta Air Lines spent $11.8 billion on 3.86 billion gallons of jet fuel.

In addition to obtaining the jet fuel produced at Trainer, the air carrier inked three-year deals with BP and Phillips 66 to exchange gasoline and other refined products processed at the refinery.

Equally important, the acquisition prevents the planned closure of the Trainer refinery, a move that would have reduced the supply of jet fuel on the East Coast by more than 20 percent. With a substantial presence at the LaGuardia and plans to expand its facilities at JFK, Delta Air Lines fuel costs could have ballooned further if Phillips 66 had shuttered the refinery.

Although reduced refining capacity on the East Coast should help bolster margins at the remaining facilities, the acquisition still exposes Delta Air Lines to feedstock costs. To address this challenge, management highlighted the potential to transport cost-advantaged crude oil from the Midcontinent region via train and barge.

Much of the scuttlebutt around this deal has focused on whether the transaction makes Delta Air Lines a more attractive investment. While shares of US Airways (NYSE: LCC) can serve as a useful hedge against lower oil prices, investors should steer clear of domestic airline stocks outside of this special situation.

That being said, Delta Air Lines’ acquisition of the Trainer refinery highlights two investable trends that we track in The Energy Strategist.

First, the deal serves as a reminder that the dramatic increase in US oil and gas output from the nation’s shale fields is reconfiguring the energy landscape and leading to unforeseen price imbalances as midstream operators bring new takeaway capacity onstream.

At the same time, Delta Air Lines’ unconventional approach to addressing rising fuel costs underscores the challenge of managing these expenses–a trend on which World Fuel Services Corp (NYSE: INT) seeks to capitalize. The company isn’t involved in oil and natural gas production; rather, the company serves as a middleman to customers looking to reduce fuel costs.

World Fuel Services purchase aviation and marine fuels in bulk, passing on a portion of the savings to its global customer base. The firm’s global energy distribution network also shields its clients from the expense associated with building and maintaining an in-house energy logistics solution.

As a middleman, the outfit earns a spread between the price it pays for buying fuel in bulk and the price it charges customers for fuel and ancillary logistical services. In general, rising or falling energy prices don’t have a significant impact on the company’s margins, as these price fluctuations are reflected in the rates charged to customers. However, extreme shifts in energy prices can stimulate or destroy demand, which would affect the company’s business.

Volatile oil prices make it tougher for firms in energy-intensive businesses to manage fuel-related expenses. In this environment, World Fuel Services’ promise of consistent fuel supplies and cost savings is an easy sell.

Around the Portfolios

Growth Portfolio

Baker Hughes (NYSE: BHI)–04/24/12
BG Group (LSE: BG/, OTC: BRGYY)–05/03/12
Cameron International (NYSE: CAM)–04/26/12
Chesapeake Granite Wash Trust (NYSE: CHKR)–N/A
Core Laboratories (NYSE: CLB)–04/19/12
Dresser-Rand Group (NYSE: DRC)–04/27/12
Eagle Rock Energy Partners LP (NSDQ: EROC)–05/02/12
Ensco (NYSE: ESV)–05/03/12
EOG Resources (NYSE: EOG)–05/09/12
Linn Energy LLC (NSDQ: LINE)–04/26/12
Mid-Con Energy Partners LP (NSDQ: MCEP)–06/06/12*
Nordic American Tanker Shipping (NYSE: NAT)–05/09/12
Occidental Petroleum Corp (NYSE: OXY)–04/26/12
Peabody Energy Corp (NYSE: BTU)–04/19/12
Petrobras (NYSE: PBR A)–05/14/12*
SandRidge Mississippian Trust I (NYSE: SDT)–N/A
SandRidge Mississippian Trust II (NYSE: SDR)–N/A
SandRidge Permian Trust (NYSE: PER)–N/A
Schlumberger (NYSE: SLB)–04/20/12
Suncor Energy (TSX: SU, NYSE: SU)–04/30/12
Weatherford International (NYSE: WFT)–04/24/12
World Fuel Services (NYSE: INT)–05/01/12

Conservative Portfolio

Chevron Corp (NYSE: CVX)–04/27/12
Eni (Milan: ENI, NYSE: E)–04/27/12
Enterprise Products Partners LP (NYSE: EPD)–05/02/12
Kinder Morgan Energy Partners LP (NYSE: KMP)–04/18/12
Natural Resource Partners LP (NYSE: NRP)–05/04/12*
NuStar Energy LP (NYSE: NS)–04/25/12
Penn Virginia Resource Partners LP (NYSE: PVR)–04/27/12
Sunoco Logistics Partners LP (NYSE: SXL)–05/02/12
Teekay LNG Partners LP (NYSE: TGP)–05/18/12
Total (Paris: FP, NYSE: TOT)–04/27/12

Aggressive Portfolio

Each earnings season, The Energy Strategist takes a detailed look at oil-field services giant Schlumberger’s (NYSE: SLB) quarterly results and subsequent conference call with analysts. One of the best-managed firms in the business, Schlumberger’s international reach and diverse operations–not to mention CEO Paal Kibsgaard’s candor about emerging trends in the energy patch–make the company’s quarterly conference calls must-attend events. In this issue, we analyze the key takeaways from Schlumberger’s earnings call and their implications for our investment strategy.

Some of the highlights from this quarter’s conference call include accelerating drilling activity in the deepwater Gulf of Mexico and a tightening market for marine seismic services as producers step up offshore exploration. I’ve also made a few changes to my Best Buys List, which highlights my favorite picks in the current market environment.

In This Issue

The Stories

1. Schlumberger’s first-quarter conference call reaffirmed our belief that the stock will outperform its peers in the coming year. Equally important, CEO Paal Kibsgaard’s commentary on developments in the oil and gas industry furnished a number of investable trends. Here’s a rundown of the key takeaways. See The World According to Schlumberger.

2. Paying close attention to the trends that Schlumberger highlights in its quarterly earnings releases and conference calls–and investing accordingly–often pays off. See Top Energy Growth Trends and How to Play Them.

The Stocks

Schlumberger (NYSE: SLB)–Buy < 100 in Growth Portfolio
Halliburton (NYSE: HAL)–Hold in Energy Watch List
Weatherford International (NYSE: WFT)–Buy < 20 in Growth Portfolio
Petroleum Geo-Services (Oslo: PGS, OTC: PGSVY)–Buy < 17.50 in Aggressive Portfolio
SeaDrill (NYSE: SDRL)–Buy < 45 in Aggressive Portfolio
Ensco (NYSE: ESV)–Buy < 60 in Growth Portfolio
Pacific Drilling (NSDQ: PACD)–Buy < 11 in Aggressive Portfolio
US Silica (NYSE: SLCA)–Buy < 19.50 in Aggressive Portfolio

Paying close attention to the trends that Schlumberger (NYSE: SLB) highlights in its quarterly earnings releases and conference calls–and investing accordingly–often pays off. Based on comments from Schlumberger’s CEO Paal Kibsgaard and the management teams at the other major oil-field services firms, energy investors should take several actions to position their portfolios.

Investors shouldn’t load up on shares of Halliburton (NYSE: HAL), which trade at less than 10 times the Bloomberg consensus estimate of 2012 earnings. Valuation metrics might suggest that the stock is a good value, but Schlumberger’s take on the supply-demand balance and pricing weakness in the pressure-pumping market suggests otherwise.

The consensus estimate of Halliburton’s 2012 earnings has already tumbled by $0.28 per share, while downward revisions have lowered the consensus forecast for the company’s 2013 earnings by about $0.44 per share. Analysts have consistently lowered their estimates of Halliburton’s earnings since mid-2011.

Until the US gas-directed rig count and/or pressure-pumping prices bottom, shares of Halliburton will trade sideways at best and underperform names with more exposure to the ongoing recovery in international markets. Halliburton is a value trap for new investors and rates a hold in the Energy Watch List.

Although a recent accounting restatement hurt management’s credibility, Weatherford International’s (NYSE: WFT) robust overseas operations and limited exposure to pressure pumping should enable the stock to outperform in the back half of the year.

Shares of Weatherford International rallied slightly after the firm reported weak first-quarter earnings and disappointing full-year guidance, suggesting that investors have low expectations for the stock. Weatherford International rates a buy under 20 and retains its position in my Best Buys List.

With supply-demand conditions tightening in the market for vessels that collect marine seismic data, Aggressive Portfolio holding Petroleum Geo-Services (Oslo: PGS, OTC: PGSVY) should thrive. The Norway-based company owns a fleet of 14 offshore seismic vessels and 21 seismic data processing centers.

Petroleum Geo-Services reports first-quarter results on May 8, 2012. In the fourth quarter, the firm’s seismic backlog jumping to $678 million from less than $500 million in the third quarter. Management noted an uptick in demand for multi-client and contract seismic services. The market should tighten further in 2012, with demand expected to increase by at least 10 percent in 2012 and the global fleet expected to grow by only 6 percent.

Petroleum Geo-Services has encountered a few operational issues that have weighed on recent results. For example, a number of the firm’s vessels were forced to return to the shipyard for maintenance and repairs late last year, pushing down the fleet-utilization rate and saddling the company with additional costs. Management initiated a profit improvement program toward the end of 2011 to reduce costs and address these issues, but it’s unclear how soon these efforts will bear fruit.

Although Petroleum Geo-Services isn’t as profitable as Schlumberger’s WesternGeco subsidiary, improving market conditions will drag the Norway-based firm’s margins higher. We also believe expect management to get the company’s operations back on track as the year progresses.

Moreover, earnings estimates for the stock haven’t increased despite the significant improvement in the market for seismic services. With a low bar of expectations, the company could surprise to the upside.

A more aggressive play than Schlumberger, Petroleum Geo-Services’ American depositary receipt rates a buy under USD17.50 and appears in the Higher-Risk portion of my Best Buys List.

Schlumberger CEO Paal Kibsgaard’s bullish comments about deepwater drilling in general and the resurgence of activity in the US Gulf of Mexico bode well for the deepwater contract drilling business. The model Portfolios contain three contract drilling stocks: SeaDrill (NYSE: SDRL), Ensco (NYSE: ESV) and Pacific Drilling (NSDQ: PACD).

At the end of April, SeaDrill announced that it secured a three-year fixture for one of its deepwater semi-submersible rigs for a day-rate, including bonuses, of almost $650,000. The contract begins in the second quarter of 2010, and the rig will operate offshore West Africa.

Day-rates earned by deepwater rigs last eclipsed $600,000 at the height of the last boom in deepwater exploration. That producers are willing to pay such a high rate to secure a rig in 2013 suggests that the supply-demand balance remains ultra-tight and that the current fleet won’t be able to handle all the deepwater work producers are contemplating.

With one of the highest-quality fleets in the business and a dividend yield of more than 8 percent,  SeaDrill rates a buy under 45.

Shares of Pacific Drilling have lagged over the past two months, likely because the stock went public at the end of 2011 and investors may not fully recognize the company’s earnings and growth potential.

The small-cap contract driller has four deepwater drillship rigs currently under contract at solid day-rates, while the two new rigs slated for delivery in 2013 should secure favorable fixtures. Pacific Drilling Rates a buy under 11 and appears on my Best Buys List.

During an analyst day on April 11, Ensco’s management team shared its bullish outlook for day-rates through at least 2013. Ensco also has the financial capacity to build more deepwater and ultra-deepwater rigs to its standardized design over the next few years to take advantage of rising rates. Ensco rates a buy under 60 in the Growth Portfolio.

Finally, investors must understand that Schlumberger’s comments about pressure pumping don’t indicate the industry’s waning interest in developing unconventional oil and gas fields. Rather, declining profit margins in pressure pumping are a symptom over overcapacity in the hydraulic fracturing services industry.

With development in liquids-rich shale plays expected to continue apace, the market for proppant–sand or ceramic material that props open the fracture reservoir rock–will tighten even further. US Silica (NYSE: SLCA) is the second-largest producer of commercial-grade silica (quartz sand) in the US. The company produces its silica by extracting quartz from open-pit mines and crushing and processing the mineral into sand.

Source: Silica Holdings 10-K, filed March 20, 2012

The primary end markets for commercial silica include the oil and gas production industry, glassmaking, building products and the metal foundry industry. In many of these end markets, there are few, if any, substitutes for commercial-grade silica because of its resistance to crushing and other difficult-to-replicate qualities.

The dynamics of silica demand have changed dramatically in recent years. As recently as 2004, industrial processes such as the manufacture of glass, building materials and metal castings accounted for almost 88 percent of silica demand. Today, the energy industry is the largest single end market for silica, and this growth trend should continue in coming years.

Source: Bloomberg

This paradigm shift in silica demand stems from the rapid development of shale oil and gas plays.

Producers mix either silica sand, resin-coated sand or ceramic material into the fracturing fluid to act serve as a proppant. The material enters the fissures created during the hydraulic fracturing process and literally props them open so that these cracks don’t close up once the pressure is removed.

Producers must use sand that meets certain standards set by the American Petroleum Institute (API) for shape, size and resistance to crushing. The most common proppant used in the oil and gas industry is API-grade silica sand, which accounts for about 80 percent of the market. Meanwhile, resin-coated sand–silica sand coated with a resin to makes it smoother and more crush-resistant–accounts for another 10 percent of the market. Ceramic proppant manufactured by firms such as CARBO Ceramics (NYSE: CRR) is more expensive and accounts for the remaining 10 percent of the market.

The US horizontal rig count serves as a good gauge of demand for commercial-grade silica. Horizontal drilling is one of the key innovations that enable producers to unlock the hydrocarbons trapped in low-permeability formations. By drilling laterally off a vertical shaft, producers expose the well to more of the productive layers.

Over the past three years, the US horizontal rig count has soared to more than 1,150 units in early 2012 from a low of 372 rigs, a trend that reflects the frenzied development of shale oil and gas plays.

Shares of US Silica have slumped from a high of almost $22 to less than their initial public offering price because of concerns that drilling activity will diminish this year. We expect the US rig count to hold steady or increase by 5 percent in 2012 as producers shift their emphasis from dry-gas fields to liquids-rich plays.

But the rig count alone isn’t the only driver of proppant demand.

As operators gain experience in the major shale plays and better understand the geology, they grow more efficient and can drill more wells with the same or fewer rigs. Even with a flat rig count, producers may drill more wells.

Producers now drill longer horizontal segments for their wells. A few years ago, a producer might have drilled a 5,000-foot horizontal well; today, lateral segments often exceed 10,000 feet. Longer wells involve more fracturing stages, which translates into more proppant per well. The industry has also found that increasing the amount of proppant used to complete each fracturing stage yields superior initial production rates and overall productivity.

In addition to rising demand, US Silica benefits from certain company-specific advantages.

First, the company has a total of 316 million tons of silica sand reserves, about 148 million tons of which should qualify as API grade. In addition, the firm benefits from some of the lowest production costs in the US. The company’s reserves are located near key rail links, which reduces transportation time and costs–a distinct advantage and a major cost center for some competitors. US Silica believes it’s the only proppant producer capable of delivering its product to all the major shale fields in the US.

Moreover, investors must consider the type of proppant the company can produce. As a rule of thumb, dry natural gas fields are located further underground, where temperatures and geologic pressures are intense. (That’s why exploration and production companies sometimes refer to a field being “too cooked” to produce oil). Oil- and liquids-rich plays, on the other hand, are often located at shallower depths and under less extreme pressures and temperatures.

Ceramic proppant resists crushing better than sand, but it’s also more expensive. Historically, producers have opted for ceramic proppant in deep-lying gas formations that contain little or no natural gas liquids (NGL).

However, with natural gas prices at depressed levels, many producers have decided not to pay up for ceramic proppant even if it leads to better production rates. These trends, coupled with a shift in drilling activity from dry-gas fields to liquids-rich plays, explains why shares of CARBO Ceramics have lagged over the past year. Since US Silica produces silica sand proppant and will launch a resin-coated variety, the company stands to benefits from the shift away from dry-gas fields and ceramic proppant.

In addition, not all sand is identical. US Silica’s coarse, white Ottawa sand is best-suited for formations that contain oil and NGLs, while finer, brown sands are the proppant of choice for budget-minded producers targeting natural gas. As drilling activity in liquids-rich plays continues to accelerate, demand for US Silica’s wares should grow significantly.

The supply side of the equation should also support higher prices for US Silica’s output. During the financial crisis and Great Recession, traditional industrial demand for silica sand contracted to 19.1 million tons in 2009 from 28.8 million tons in 2006. Although the oil and gas industry’s demand for silica sand increased over this period, the market remained oversupplied. As a result of the decline in overall demand, producers curtailed investments in new supply.

It’s not a simple matter to increase silica sand production. It can take 12 months or longer to find an appropriate deposit, one to three years to obtain the necessary permitting from the government, and two to three years to site and build mining, processing and transportation infrastructure. Two to three years would be the minimum time frame to bring a greenfield silica project online. As demand surged in 2011 and into early 2012, supply growth has remained sluggish because of a lack of investment.

However, US Silica has expanded its capacity to produce silica sand significantly. In 2011 the firm completed a project that increased the annual production capacity of its Ottawa, Ill., operation by 1.2 million tons and expanded a plant in Michigan.

To fund these endeavors, the company signed take-or-pay contracts with customers that guarantee minimum cash payments regardless of whether the silica sand is used. As both facilities produce the coarse, white sand used in liquids-rich fields, this material will likely be in high demand.

US Silica will launch a line of resin-coated sand once the firm completes a plant in Illinois that’s capable of producing about 200,000 tons of the proppant. Management expects this facility to be up and running in 2013.

The company has also identified additional brownfield expansion projects at its existing facilities that could add incremental capacity. Longer-term production growth could come from reserves acquired in Wisconsin. The company expects to complete construction on a production plant by the end of 2013 and to start churning out silica sand in 2014. Management expects this facility to produce about 500,000 tons of proppant per annum.

In 2009 the oil and gas industry accounted for only 19 percent of the company’s sales, compared to about 36 percent in 2011. Management estimates that energy companies will generate two-thirds of the firm’s sales by the end of 2013. Spot silica sand prices have surged over the past two years, and with demand expected to increase at an annualized rate of 15 percent through 2014, prices have room to grow. 

And even if spot prices remain flat, US Silica will reap the rewards as supply contracts signed in 2008-09 roll off and are replaced with deals that feature more lucrative terms.

Shares of US Silica trade at roughly 11 times projected 2012 earnings, while CARBO Ceramics’ stock fetches more than 13 times forward earnings–a huge disparity when you consider US Silica’s superior growth prospects and that the company has the potential to grow its earnings at an average annualized rate of 30 percent to 40 percent.

With North America-focused services firms struggling to secure sufficient proppant to meet demand and drilling in liquids-rich shale plays accelerating, US Silica’s growing production makes the stock a buy up to 19.50 in the Aggressive Portfolio and in my Best Buys List.

Each earnings season, The Energy Strategist takes a detailed look at oil services giant Schlumberger’s (NYSE: SLB) quarterly results and subsequent conference call with analysts. One of the best-managed firms in the business, Schlumberger’s international reach and diverse operations–not to mention former CEO Andrew Gould’s candor about emerging trends in the energy patch–made the company’s quarterly conference calls must-attend events.

Gould’s successor, Paal Kibsgaard, has proved equally perceptive and highlighted a number of profitable trends during Schlumberger’s conference call to discuss first-quarter earnings.

Schlumberger (NYSE: SLB)

Oil services giant Schlumberger reported first-quarter earnings per share (EPS) of $0.98 on revenue of $10.611 billion, beating the Bloomberg consensus estimate, which called EPS of $0.97 and $10.541 billion in sales.

EPS slipped by $0.13 sequentially, reflecting the annual budget flush that occurs in the fourth quarter, when energy companies splurge on software and multi-client seismic data. Schlumberger’s software packages model and analyze field data, manage the production of wells and model oilfield behavior. Multi-client databases of seismic information include data on rock formations that’s available to multiple purchases.

Meanwhile, cold weather in the North Sea and parts of China and Russia often produces a seasonal slowdown in exploration and development activity in the first quarter. And although the US and Canada enjoyed one of the warmest winters on record, China endured one of the coldest in recent history, while temperatures in much of Russia were colder than usual.

Source: National Oceanic and Atmospheric Administration

Given these seasonal variances, year-over-year comparisons are a more relevant measure of Schlumberger’s first-quarter performance. On that basis, the firm’s EPS surged by 39 percent.

The stock’s post-earnings strength likely reflects the market’s low expectations and management’s bullish commentary on profit margins in international and deepwater markets. Here’s a review of the key takeaways from Schlumberger’s earnings report and subsequent conference call.

North America

Schlumberger’s business in North America weakened in the first quarter, and management’s comments suggest that the outlook for this market remains cloudy. Schlumberger was the first of the major oil services firms to warn that profit margins in the red-hot North American market could take a hit. At the time, Halliburton (NYSE: HAL) aggressively expanded key service lines in this market.

First-quarter results give credence to Schlumberger’s early warning: The company’s revenue in North American declined 3.5 percent sequentially, while profit margins plummeted by more than 4 percent to 22.8 percent. Softening prices in the pressure-pumping business accounted for much of this weakness.

Pressure pumping is a critical service related to hydraulic fracturing, a production technique that’s critical to extracting oil and natural gas trapped in shale and other “tight” formations.

Oil and natural gas don’t exist in giant underground lakes or caverns. Rather these hydrocarbons are trapped in the pores, cracks and crevices of solid rock. In a conventional reservoir, these pores are well-connected so that when producers complete a well, the geologic pressure is sufficient to impel hydrocarbons through the reservoir and to the surface. But in shale formations and other “tight” plays, the reservoir rock lacks permeability.

Hydraulic fracturing is a process whereby producers pump a liquid into the shale reservoir under such tremendous pressure that it cracks the rock. This creates channels through which oil and natural gas can travel. Over the past several years, US producers have honed this technique in a number of prolific shale oil and gas plays.

Pressure-pumping services require huge compressors that pumping the fracturing fluid into the well under tremendous pressure. This formerly high-flying business line has come under pressure from several angles, including a collapse in natural gas-directed drilling activity.

Source: Bloomberg

This graph tracks the US oil-directed and gas-directed rig counts. With domestic natural gas prices below $2 per million British thermal units (Btu), even operators with the lowest production costs struggle to reap a profit.

Accordingly, producers continue to reduce drilling activity in plays that produce primarily natural gas, choosing instead to allocate capital to operations in fields bearing oil and natural gas liquids. In fact, the number of active rigs targeting natural gas has declined to 613 units from almost 1,000 units in early 2010. We expect the gas-directed rig count to decline even further, especially now that operators hold much of their acreage by production and don’t need to drill at a frenzied pace to maintain their leaseholds. (See Pugh Clauses and Shale Gas Actvity.)

As we’ve noted in previous issues of The Energy Strategist, We don’t see much upside for natural gas prices over the next two to three years. Schlumberger CEO Paal Kibsgaard echoed this assessment during an April 20 conference call with analysts: “In the US, production growth from unconventional gas, coupled with very mild winter weather has driven storage to record levels. This has sent gas prices to a 10-year low and has led to a subsequent drop in gas activity which is unlikely to recover in the near term.”

The outlook for oil-directed drilling activity is decidedly more sanguine. With West Texas Intermediate crude oil prices currently fetching more than $100 per barrel and Brent crude oil going for almost $120 per barrel, the number of US rigs targeting oil has climbed to more than 1,300 from less than 200 in spring 2009.

Thus far, the upsurge in oil-directed drilling has largely offset waning activity in the Haynesville Shale and other plays that primarily produce natural gas. The overall rig count has held steady this year but still hovers near its highest level since the early 1980s.

Source: Bloomberg

Although the overall rig count hasn’t declined significantly, the great migration to liquids-rich plays from dry-gas fields will continue to weigh on profit margins associated with pressure pumping. 

Kibsgaard elaborated on these challenges during the Q-and-A portion of Schlumberger’s recent conference call:

Now there’s another thing to realize as well, and that is that in the liquids, there are more [fracturing] stages per well but the horsepower required per stage is actually much lower because we pump at lower pressures and lower rates. So while you need the [pressure pumping] fleets in liquids, you actually need fewer pumps or less horsepower per fleet in the liquids, which again, is going to contribute to the oversupply of horsepower. So if you add to these factors the fact that there’s significant horsepower on order for the industry, we believe there is considerable uncertainty around the outlook for pressure pumping prices and the margins.

As Kibsgaard explains, pressure-pumping requirements in shale oil and shale gas plays differ dramatically. Oil wells in unconventional plays usually involve more fracturing stages; in the Bakken Shale of North Dakota, for example, some producers routinely use more than 40 fracturing stages along the lateral portion of the well.

Successfully fracturng the reservoir rock in a high-pressure gas field requires a lot of horsepower to overcome the counterforce.

Although oil wells in unconventional plays usually involve more fracturing stages, less horsepower and fewer pressure-pumping trucks are required than in a natural gas-bearing shale formation. In short, as the industry shifts its sights from natural gas to liquid hydrocarbons, rig demand should hold steady. But companies that provide pressure pumping will feel the pain.

At the same time, services firms have expanded their pressure-pumping capacity significantly in recent years to take advantage of pricing power as producers rushed to drill wells in shale gas plays and hold their acreage by production. With a backlog of pressure-pumping units that have yet to be delivered, this business line faces the challenge of weakening demand and rising capacity–a nightmare scenario for profit margins.

Kibsgaard noted that pressure-pumping providers now bid against each other to secure work, a far cry from six to 12 months ago, when producers paid up to ensure access to horsepower.

Schlumberger’s CEO also estimated that this deteriorating supply-demand balance had driven down prices for this service by 20 percent in gas-producing basins and 10 percent in liquids-rich plays. In his commentary on the company’s fourth-quarter results, Kibsgaard indicated that the price of pressure-pumping services had declined in shale gas plays and held steady in unconventional oil fields.

In his most recent comments, Kibsgaard stated that further pricing deterioration in the second quarter was “a given” and predicted that profit margins in this business line would tighten in the second half 2012.

Schlumberger can afford to be candid about the challenges facing pressure-pumping operators because the firm has less exposure to North America than any of the Big Four oil-field services outfits. Whereas Schlumberger generated roughly one-third of its 2011 revenue from North America, the region accounted for almost 60 percent of Halliburton’s sales, 55 percent of Baker Hughes’ (NYSE: BHI) revenue and 47 percent of Weatherford International’s (NYSE: WFT) sales.

Although the Big Four don’t disclose how much pressure pumping contributes to their top line, we can get a reasonable idea by looking at the performance of certain business segments and weighing management’s comments.

Halliburton and Baker Hughes, for example, report results for completion and production, a category that accounts for about 60 percent of each firm’s annual revenue and would encompass pressure pumping and other service lines. The two management teams have also highlighted their respective companies’ aggressive investments to build pressure-pumping capacity and take advantage of growing margins in North America.

Meanwhile, Growth Portfolio holding Weatherford International generates about 17 percent of its revenue from stimulation, a business line that’s predominantly pressure pumping. Despite Weatherford International’s outsized exposure to North America, the firm has relatively little exposure to challenges in the market for pressure pumping.

In the past, Schlumberger has attributed roughly two-thirds of its revenue from exploration-related services, a business mix that would limit its exposure to production-related services such as pressure pumping and hydraulic fracturing. Add in the company’s relatively modest presence in North America and it becomes clear that the firm’s exposure to the weakest part of the oil-field services business is minor compared to its peers.

Investors should commend Schlumberger’s management team for its prescient diagnosis of the emerging weakness in North American profit margins–a contrarian call at a time when its peers were rushing to add capacity. Based on this outlook, the company made only moderate additions to its pressure-pumping fleet and targeted the high-end of the market with its HiWay fracturing system.

Rather than relying on the brute force of additional horsepower to complete hydraulic fracturing jobs, Schlumberger focused on optimizing the design of each job and the composition of the fluids involved in the process. These innovations produced a system that uses less water and less proppant–sand or ceramic material that props open the cracks created by pressure pumping–than traditional approaches to hydraulic fracturing.

Despite the weakness in the pressure-pumping market, Schlumberger’s HiWAY system continues to win market share; in the first quarter, the company completed 25 percent more HiWAY fracturing stages than in the final three months of 2011.

This success represents only the latest instance of Schlumberger’s commitment to innovation and focus on the high-tech services, a strategy that often yields higher margins and distinguishes the company from the competition. In 2011 Schlumberger spent almost $1.12 billion on research and development (about 2.7 percent of revenue), dwarfing its peers’ investments.

Source: Bloomberg

We share management’s enthusiasm for the SPARK program, a new business model for hydraulic fracturing that replicates the strategies that have made Apple (NSDQ: AAPL) such a success in the tech space.

Apple designs and engineers its popular iPhones, iPads and related software in California, while outsourcing the manufacture of components and assembly of the devices. In this instance, the design of the product itself and Apple’s intellectual property is the most valuable part of the process.

Under the SPARK program, Schlumberger provides customers with access to its engineering expertise and advanced technologies but outsources the grunt work. The firm designs the fracturing job and optimizes the fluid mix–the high-margin, proprietary part of its business–but allows its customers to secure the trucks, work crews and pressure-pumping horsepower.

Not only does the SPARK platform appeal to producers that own and operate their own fracturing equipment, but this approach also sets the table for Schlumberger to eventually disaggregate the technology and advanced engineering segments of fracturing from the capital-intensive, lower-margin components of the business.

Outside of the pressure-pumping arena, Schlumberger’s North American business fared well in the first quarter, with its onshore operations growing revenue on higher sales volumes in the wireline logging, coiled tubing and other drilling product lines. Management reported that sales prices were flat to slightly higher.

Wireline logging enables producers to monitor electronically the rock formations surrounding a well and the fluids and gases in the reservoir, information that’s critical to developing an optimal, site-specific drilling plan. Coiled tubing is a long, flexible pipe that’s inserted into a well to perform drilling, maintenance and repair operations.

Demand for these offerings may benefit from the move to oil basins from gas-focused plays, and neither service line faces excess capacity.

Meanwhile, Schlumberger’s business offshore North America continues to gain momentum, as activity in the deepwater Gulf of Mexico has benefited from an uptick in the number of drilling permits issued this year. The firm’s operating profit margins in the Gulf of Mexico have returned to levels that prevailed before the Macondo oil spill–an encouraging sign for future earnings growth when you consider Schlumberger’s leading position in deepwater services

Kibsgaard offered a good summary of the issues facing Schlumberger in North America during the company’s April 20 conference call with analysts:

[I]t is clear that Q2 [margins] are coming down and that’s due to the fact that there’ll be more impact on the pressure-pumping pricing and we have the Canada breakup. Now, what is going to happen in the second half of the year, I think that pressure-pumping margins are going to continue to be under further pressure. Now, to what extent can we offset this from seismic, from deepwater drilling in the Gulf of Mexico, and from the other part of our land offering, which is actually holding up well in activity and actually holding up very well in margins , obvious, we have the ambition of trying to offset as much as possible of this. Now, whether we’re going to be able to do that is going to be a function of how severe the pressure-pumping and margin decline is going to be and at this stage I simply don’t know.

In short, the challenges in the pressure-pumping market have weighed on the company’s North American operations to an extent, but the company’s resurgent offshore business and thriving onshore product categories help to offset these headwinds.

International

Pricing trends in international markets continue to improve. Although Schlumberger’s revenue from these operations dipped by 4 percent sequentially, this weakness reflects the customary, year-end surge in sales of software and multi-client seismic data. Colder-than-usual weather in China, Russia and the North Sea also disrupted business in the first quarter.

Despite these seasonal challenges, profit margins held steady at 19.1 percent–an indication that Schlumberger earned more from the work that it performed during the quarter.

Management highlighted several areas of strength in international markets, including deepwater exploration and development in East and West Africa and strong onshore drilling activity in the Middle East and North Africa.

Kibsgaard’s assessment of the pricing trends in international markets should encourage investors who have patiently waited for profit margins to improve:

[I]t’s also worthwhile to note that over the past two years, most of the international contracts have been rebid, so there’s now an opportunity to start raising prices in the smaller upcoming contracts, which we are in the process of doing. And if you look at what’s happening in rigs and in seismic, typically there the contract size is smaller and that’s why you can see them move quicker in terms of testing prices.

With big multi-segment, multi-year and multi-rig contracts, like some of the big ones we have been bidding on over the past two years, you really don’t want to be shut out, and I think that’s where pricing on the large contracts has been very competitive and with that kind of slightly negative pricing sentiment. But I think most of those contracts are now either bid or even awarded and there’s now an opportunity to start raising prices on the smaller upcoming contracts without any significant risks.

Over the past several years, profit margins in international markets have lagged those in the US and Canada, in part because North American producers ramped up activity in shale oil and gas plays after the financial crisis subsided. Frenzied drilling led to a shortage of capacity, which sent profit margins through the roof.

In recent years, mega-projects have predominated in international markets. These capital-intensive, multiyear endeavors often include contracts for a wide range of services, with providers competing to win the most lucrative work and avoid being relegated to a minor role.

To ensure their slice of the bounty, service providers offer price cuts and concessions, which lower profitability. This competition intensified in the wake of the financial crisis and collapse in commodity prices; the Big Four oil-field services firms had plenty of excess capacity and often sought to underbid the competition to ensure their assets were fully utilized.

Fortunately, many of these high-profile contracts have already been bid or awarded. Going forward, most of the contracts on offer outside North America are smaller deals or shorter-term projects. With less competition for these deals, oil-field services firms should be able to test higher prices. 

Moreover, the sharp rebound in commodity prices has led to an upsurge in exploration and development, tightening capacity in international markets. At this point, much of the excess equipment and manpower that was idle in 2009 has returned to work. We expect this tightness to support margin growth in coming quarters, especially for Schlumberger and Weatherford International, both of which have significant overseas operations.

Marine Seismic

Schlumberger’s marine seismic division, WesternGeco, has been a pocket of strength, as surging demand has bolstered profit margins.

The percentage of WesternGeco’s fleet that’s been engaged to collect seismic data was elevated in the first quarter and is completely booked for the second quarter. Management also reported that the order book for the third quarter is filling up quickly and that the backlog of seismic work climbed by 16 percent in the first three months of the year.

Much of this uptick in activity has involved contract work–collecting seismic data for a particular company–rather than assembling multi-client data.

Although some of these contracts were inked last year and feature lower prices, management noted that the company has boosted the charge for new work by 10 percent sequentially and expects pricing power to improve as the year progresses.

This development suggests that producers plan to increase spending on deepwater activity and that the excess capacity plaguing the marine seismic industry has finally abated.

Asked by an analyst whether WesternGeco’s profit margins could hit their 2007-08 peak by 2013, Kibsgaard offered a guardedly optimistic response:

Again, I think it’s too early to say. We are starting to see the signs of pricing traction, which we have been looking for, for the past 12 or 18 months. So capacity has tightened. If I look at the number of 3D vessels coming into the market scheduled for this year, which I think for the total market is only around three, I don’t see any issues with further capacity additions in terms of how it will impact pricing. So I think there are good chances of getting sustained pricing traction, at least through this year, and then it’s going to be a function of, I think, how much capacity is being added to the market. But the fact that margins are coming up is clear, but I think it’s too early to say yet whether we’re going to see the peak margins of the previous cycle, and I think multi-client activity is also going to play into that equation.

In the April 2, 2012, issue of MLP Profits, we explained the basics of gas processing and the growth trends at work in this market. Here’s a refresher course.

In the field, raw natural gas often occurs with other hydrocarbons such as ethane, propane, butane and iso-butane. These heavier hydrocarbons are collectively known as natural gas liquids (NGL).

Processing involves separating the NGLs from the raw gas, which ensures that the methane (natural gas) meets purity requirements for transportation on the interstate pipeline network and delivery to homes and businesses.

More important, NGLs have value as discrete commodities; the relative spread between the price of natural gas and a barrel of NGLs drives demand for processing. That is, if natural gas prices are low compared to the price of a barrel of NGLs, companies have an incentive to extract as much of this content as possible from the raw gas. Conversely, if gas prices are expensive relative to NGLs, demand for processing would suffer. In this instance, companies would leave as much NGLs as possible in the gas stream without violating pipeline requirements.

Fortunately, the market value of a barrel of NGLs tends to follow the oil prices rather than the price of natural gas, as ethane and propane can replace naphtha and other crude derivatives in certain petrochemical processes. The combination of elevated oil prices and depressed natural gas prices has been a boon for MLPs that own processing capacity, though NGL prices have softened somewhat of late.

Source: Bloomberg

Several factors are behind the moderate decoupling between oil and NGL prices. Frenzied drilling activity in liquids-rich plays such as Appalachia’s Marcellus Shale, south Texas’ Eagle Ford Shale and parts of the Barnett Shale near Fort Worth, Texas, have led to a surge in NGL production.

Nevertheless, investors shouldn’t fret that NGL output will swamp demand and weigh on prices. For one, international demand for US propane exports has outstripped existing capacity, prompting Conservative Portfolio holding Enterprise Products Partners LP (NYSE: EPD) and Targa Resources Partners LP (NYSE: NGLS) to announced plans to build or expand their terminals on the Gulf Coast. Propane and other NGLs are far more expensive in other areas of the world, giving US exports a competitive advantage against local supplies.

The revivification of the domestic petrochemical industry also ensures that NGL prices won’t tank. To take advantage of low US NGL prices and plentiful supplies, several major chemicals manufacturers have reopened manufacturing facilities in the US and announced plans to build new ethane and propane crackers.

With demand for natural gas processing expected to remain robust in the current pricing environment, Enterprise Products Partners LP rates a buy when the stock dips to less than 35. Targa Resources Partners LP is a buy under 35.

US equities have endured a difficult decade, with the S&P 500 posting an average annual gain of less than 5 percent. If you purchased stocks at the height of the tech bubble in 2000 or the credit bubble in 2007–or sold positions in a panic when these bubbles burst–you’re probably nursing considerable losses.

The S&P 500 Energy Index, on the other hand, has returned a whopping 185 percent over the past 10 years, equivalent to an average annual gain of roughly 11 percent. Meanwhile, the Alerian MLP Index, which tracks the 50 largest energy-focused MLPs, is up more than 340 percent over the same period and sports a beta of 0.71.

The Alerian MLP Index has generated market-beating returns with less volatility than the S&P 500.

One stock has outperformed the Alerian MLP Index over the past decade and exhibited even less volatility: units of Kinder Morgan Energy Partners LP (NYSE: KMP), one of North America’s largest pipeline transportation and energy storage companies.

If you had invested $10,000 in Kinder Morgan Energy Partners in late March 2002 and reinvested the quarterly distribution, your position would be worth almost $50,000. In comparison, the same initial investment in the S&P 500 would be worth $15,000 and the same stake in the Alerian MLP Index would be worth $44,000.

At the same time, Kinder Morgan Energy Partners’ stock has a beta of about 0.50; the units don’t fluctuate in price as much as the Alerian MLP Index and exhibit half the volatility of the S&P 500.

Better still, Kinder Morgan Energy Partners’ units offer a distribution yield of 5.65 percent. Over the past five years, the firm has increased its quarterly payout at an average annualized pace of more than 7 percent. The master limited partnership (MLP) has never cut its distribution and raised its payout by almost 20 percent between the end of 2007 and the first quarter of 2010, overcoming plummeting oil and natural gas prices, the worst economic downturn since the Great Depression and a severe credit crunch.

In light of this strength, you’d expect Kinder Morgan Energy Partners and its longtime CEO Richard Kinder to be the darlings of the financial media. The publicly traded partnership has its fair share of admirers, including yours truly–we’ve held the stock in The Energy Strategist’s model Portfolio since the service launched seven years ago. Investors who followed our lead and purchased the stock have been well-rewarded.

Nevertheless, I’ve read innumerable articles over the years that are down on Kinder Morgan Energy Partners and its management team, which is remarkable given the firm’s impressive asset base and the stock’s outperformance.

Negative sentiment toward Kinder Morgan Energy Partners often stems from the firm’s incentive distribution rights (IDR) structure. MLPs consist of two entities: a limited partner (LP) and a general partner (GP), which oversees day-to-day operations and makes major business decisions. Some GPs are publicly traded companies; others are privately held firms.

The best GPs take steps to grow the LP’s distributable cash flow. For example, some GPs will drop down assets to their LP at sale prices that make the deal immediately accretive to cash flow, enabling the limited partner to increase its distribution. The best GPs help their LPs to finance acquisitions, provide direct financial support when business or market conditions and provide solid leadership.

The GP doesn’t perform these functions out of charity. The relationship between GP and LP is governed by the partnership agreement, which also establishes the fees that the LP pays to the GP in exchange for its services. These IDRs are based on the size of the quarterly distribution made to LP unitholders. IDRs are tiered such that the GP gets a larger percentage cut of the cash flow when the LP distribution increases. In other words, the GP’s take only rises when the LP hikes its payout to its unitholders.

Investors must analyze the relationship between the GP and LP before investing in an MLP. Subscribers often ask how much a particular GP is charging LP unitholders to manage the business. To answer this question, you need to understand how a tiered IDR structure works.

Here’s a look at Kinder Morgan Energy Partners’ current IDR structure.

• Tier 1: 98 percent of cash flow goes to holders of Kinder Morgan Energy Partners and 2 percent to the GP, up to a quarterly distribution of $0.15125 per unit.
• Tier 2: 85 percent of cash flow goes to Kinder Morgan Energy Partners and 15 percent to the GP, up to a quarterly distribution of $0.17875 per unit.
• Tier 3: 75 percent of cash flow goes to Kinder Morgan Energy Partners and 25 percent to the GP, up to a quarterly distribution of $0.23375 per unit.
• Tier 4: 50 percent of cash flow goes to KMP and 50 percent to the GP for all quarterly distributions greater than $0.23375 per unit.

In the most recent quarter, Kinder Morgan Energy Partners distributed $1.20 per unit–much more than $0.23375 per quarter. In industry parlance, Kinder Morgan Energy Partners is in the “high splits” with its GP, which is owned by Kinder Morgan Inc (NYSE: KMI). The table below breaks down the payout received by unitholders and the IDR payments collected by Kinder Morgan Inc.

Source: Bloomberg

Many investors don’t understand how IDR payments are calculated. The quarterly distribution declared by the LP each quarter is the amount that investors receive from Kinder Morgan Energy Partners; this payout is only part of the total distribution. To calculate the IDR payment, we begin with the first tier, or all distributions up to $0.15125 per quarter. The first $0.15125 paid to Kinder Morgan Energy Partners’ unitholders represents 98 percent of the total distribution, which means the GP receives slightly less than one-third of a cent.

Repeating this calculation for all the tiers in Kinder Morgan Energy Partners’ IDR structure yields a total distribution of roughly $2.19 per unit, $1.20 of which went to LP unitholders and the remaining $0.99 of which went to the GP. In other words, the LP unitholders received about 55 percent of distributable cash flow, while the GP raked in about 45 percent.

Critics often complain that the GP’s take of Kinder Morgan Energy Partners’ total distribution is excessive. A decade ago, a 50 percent high split was the de facto standard, but many LPs have bought out their GPs in recent years.

Enterprise Products Partners LP (NYSE: EPD), for example, operated under a similar IDR structure until 2002, when the firm became the first major MLP to slash the high-splits take to 25 percent. In 2010 Enterprise Products Partners merged with its general partner, Enterprise GP Holdings, eliminating the IDRs altogether.

An onerous IDR obligation makes it difficult for the LP to grow its distribution. For Kinder Morgan Energy Partners to increase its quarterly distribution to $1.25 per unit from $1.20 per unit, the MLP would need to grow its distributable cash flow by $0.10 per unit to fund the higher LP distribution and the resulting increase to the GP’s IDR payment.

Nevertheless, the bearish case against Kinder Morgan Energy Partners doesn’t hold water. Although the MLP has been in the high splits for some time, the firm has grown its quarterly distribution to LP unitholders at an average annual rate of more than 7 percent over the past five years. This track record surpasses the average rate of distribution growth in the Alerian MLP Index. In fact, Kinder Morgan Energy Partners has increased its LP distribution at a faster pace than Enterprise Products Partners over the past half-decade.

Investors should also consider Kinder Morgan Energy Partners’ future growth prospects. In October 2011, Kinder Morgan Inc announced a deal to acquire pipeline owner El Paso Energy Corp (NYSE: EP) for $37 billion. The acquisition is expected to close in mid-2012. Management has indicated that Kinder Morgan Inc will drop down a number of assets acquired in the deal to Kinder Morgan Energy Partners. These transactions should accelerate the LP’s distribution growth. Management expects Kinder Morgan Energy Partners in 2012 to disburse $4.98 per unit–an 8 percent increase from year-ago levels–while the distribution should grow at an annualized rate of 5 percent to 7 percent over the next two years.

If these forecasts come to fruition, Kinder Morgan Energy Partners’ distribution growth rate would rank toward the top of its large-capitalization peers–so much for the high splits being an impediment.

Criticism of CEO Richard Kinder is even less justified in my view. Pundits who claim that Kinder has profited at the expense of unitholders should examine the facts. Like Enterprise Products Partners’ late founder Dan Duncan, Richard Kinder has been at the leading edge of developments in the midstream energy business.

In 1996 Kinder appeared to be first in line for the CEO job at Enron, but ultimately lost out to his colleague Kenneth Lay. Whereas Kinder saw the value in energy infrastructure such as pipelines and storage facilities, Lay’s focus on asset-light trading operations won out. Today, Kinder is a billionaire, while many of his fellow managers at Enron lost their personal fortunes in the company’s collapse or ended up in prison.

In the ensuing years, Kinder Morgan Energy Partners has amassed an enviable portfolio of pipelines and other midstream assets, many of which generate cash flow guaranteed by long-term contracts.

Another hallmark of a great CEO and manager is the ability to weather and thrive during a downturn as traumatic as the 2008-09 credit crunch and Great Recession. Those questioning Kinder’s acumen or compensation should consider this excerpt from Kinder Morgan Energy Partners’ conference call to discuss results from the third quarter of 2008:

Now, the 500 pound gorilla in the room is obviously the volatility in the capital markets. Let me just address that ahead on. I think it’s worth discussing how we expect to fund our expansion projects. Several factors here, the first and most important factor is the strength of our existing assets and our expansions. Our diverse set of energy infrastructure assets will generate about $2 billion of cash flow that can be distributed to our partners in 2008. We expect that number to increase in 2009. And let me be clear, that $2 billion is after all operating expenses, debt service, and sustaining capital expenditures. That’s a very important factor in the strength of our capital structure.

Number two, our expansion projects in aggregate will generate attractive returns on our investments using conservative projections secured by contracted customer commitments even after the cost overruns we talked about.

Third, we have ample access to short-term funds through unused capacity at our credit facilities. Let me talk about those. At year-end, even if we don’t put out any additional capital between now and year-end, we will still have undrawn capacity on our KMP line of well over $600 million on 12/31/2008, and we will have substantial amounts on our JV credit facilities. At REX, we expect to have well over $500 million and at Midcontinent Express well over $200 million of undrawn capacity at year-end without raising any additional capital, equity or debt, between now and year-end.

Our common units, KMR shares, and debt have performed relatively well, although I’m reminded of that old saying: in the land of the blind, the one-eyed man is king. But they performed relatively well compared to our peer group over these last several months. That’s allowed us to raise $3.4 billion of long-term debt over the last 15 months, and $843 million of equity over that period of time. Now if you include the KMR distributions, which is essentially an automatic distribution reinvestment program, we’ve raised approximately 1.2 billion of equity over that same 15 months. That gives us lot of confidence that we’ll be able to access these markets to raise new capital.

But fourth, in addition, our general partner, Knight Inc., the general partner of KMP, has substantial financial resources. This year, Knight will have EBITDA [earnings before interest, tax, depreciation and amortization] of over $1 billion for calendar year 2008 and we have a debt to EBITDA ratio of about 2.6. We’re prepared to use those financial resources if necessary, and the Board of Directors of Knight today indicated its willingness to contribute up to $750 million to purchase equity from KMP over the next 18 months, if necessary to support KMP’s capital raising efforts.

In late 2008, even AAA-rated companies struggled to borrow money because the capital markets had frozen over. But Kinder Morgan Energy Partners was set up to fund most of its required capital expenditures from internally generated funds.

In the final paragraph of this excerpt, Richard Kinder notes that Kinder Morgan Energy Partners’ GP–then a privately-held company that he controlled–offered to support the LP with a capital infusion of up to $750 million via an equity purchase. How many other CEOs stepped up to the plate like that in those dark days?

There’s an old Wall Street saw that the bearish case always seems smarter than the bullish case–but that doesn’t necessarily mean the bears are correct. This wisdom also applies to financial journalism: A story purporting to unveil how a company is overcharging its investors will undoubtedly attract more attention than a piece explaining how a firm has generated substantial wealth for investors.

Investors who avoid Kinder Morgan Energy Partners are being penny wise and pound foolish. Although the MLP’s IDR obligations may exceed those of its peers, the firm’s long-term performance and future growth prospects overshadow this concern.

In the end, Kinder Morgan Energy Partners’ distribution growth and the stock’s price appreciation speak more loudly than an army of scribblers and talking heads.

Around the Portfolios

First-quarter earnings season is under way. Here are the confirmed and estimated reporting dates for our Portfolio holdings. All dates marked with an asterisk are estimated.

Growth Portfolio

Baker Hughes (NYSE: BHI)–04/24/12
BG Group (LSE: BG/, OTC: BRGYY)–05/03/12
Cameron International (NYSE: CAM)–04/26/12
Chesapeake Granite Wash Trust (NYSE: CHKR)–N/A
Core Laboratories (NYSE: CLB)–04/19/12
Dresser-Rand Group (NYSE: DRC)–04/27/12
Eagle Rock Energy Partners LP (NSDQ: EROC)–05/02/12
Ensco (NYSE: ESV)–05/03/12
EOG Resources (NYSE: EOG)–05/09/12
Linn Energy LLC (NSDQ: LINE)–04/26/12
Mid-Con Energy Partners LP (NSDQ: MCEP)–06/06/12*
Nordic American Tanker Shipping (NYSE: NAT)–05/09/12
Occidental Petroleum Corp (NYSE: OXY)–04/26/12
Peabody Energy Corp (NYSE: BTU)–04/19/12
Petrobras (NYSE: PBR A)–05/14/12*
SandRidge Mississippian Trust I (NYSE: SDT)–N/A
SandRidge Mississippian Trust II (NYSE: SDR)–N/A
SandRidge Permian Trust (NYSE: PER)–N/A
Schlumberger (NYSE: SLB)–04/20/12
Suncor Energy (TSX: SU, NYSE: SU)–04/30/12
Weatherford International (NYSE: WFT)–04/24/12
World Fuel Services (NYSE: INT)–05/01/12

Conservative Portfolio

Chevron Corp (NYSE: CVX)–04/27/12
Eni (Milan: ENI, NYSE: E)–04/27/12
Enterprise Products Partners LP (NYSE: EPD)–05/02/12
Kinder Morgan Energy Partners LP (NYSE: KMP)–04/18/12
Natural Resource Partners LP (NYSE: NRP)–05/04/12*
NuStar Energy LP (NYSE: NS)–04/25/12
Penn Virginia Resource Partners LP (NYSE: PVR)–04/27/12
Sunoco Logistics Partners LP (NYSE: SXL)–05/02/12
Teekay LNG Partners LP (NYSE: TGP)–05/18/12
Total (Paris: FP, NYSE: TOT)–04/27/12

Aggressive Portfolio

Afren (LSE: AFR)–05/18/12*
Alliance GP Holdings LP (NSDQ: AHGP)–04/30/12
GasLog (NYSE: GLOG)–N/A
Nabors Industries (NYSE: NVR)–04/24/12
Oasis Petroleum (NYSE: OAS)–05/11/12
Pacific Drilling (NYSE: PACD)–N/A
Petroleum Geo-Services (Oslo: PGS, OTC: PGSVY)–05/08/12
SeaDrill (NYSE: SDRL)–05/31/12
Tenaris (NYSE: TS)–04/26/12

Houston-based Halcon Resources (NYSE: HK) announced an agreement to acquire Aggressive Portfolio holding GeoResources (NSDQ: GEOI) in a cash and stock deal worth nearly $1 billion.

Under the terms of the deal, GeoResources shareholders will receive $20 per share in cash plus 1.932 shares of Halcon for each share of GeoResources owned. Based on Halcon’s closing price on Tuesday, the deal is worth roughly $38 per GeoResources share–a 23 percent premium. GeoResources will likely trade at a slight discount to its takeover value until the deal closes.

As we outlined in the Jan. 19, 2012, issue of The Energy Strategist, Art of the Deal, GeoResources’ attractive mix of primarily oil- and natural gas liquids-producing properties in the Bakken Shale and the Eagle Ford Shale. GeoResources’ solid acreage positions in two of the hottest unconventional plays, coupled with the company’s small market capitalization, made it a tempting takeover target.

Sell GeoResources for a roughly 23 percent gain and allocate the proceeds to one of the other open positions in my Best Buys List.