The first three months of 2011 ushered in a number of Black Swans, unpredictable events that have major implications for global markets. At the end of 2010, the biggest risk to stocks was deepening sovereign debt woes in the EU’s peripheral economies. Although Portugal appears destined to join Greece and Ireland in tapping the EU’s bailout facility, Europe’s fiscal health hasn’t been much of a market mover.

For energy investors, the two most important Black Swans are Libya’s internecine civil war and the 9.0 magnitude earthquake and subsequent tsunami that devastated Japan’s Tohoku region. The previous issue of The Energy Strategist, The Fallout, covered the tragedy in Japan and its implications for global energy markets. This issue will update the analysis put forth in Oiling Up and Going Nuclear and examine how events in Libya will affect the outlook for crude oil, natural gas and natural gas liquids (NGL). We’ve also updated our expectations for the model Portfolio’s exploration and production (E&P) names.

In This Issue

The Stories

How our favorite E&P names fare in 2011 hinges in part on the pricing environment for the energy commodities they produce. With the civil war in Libya and Japan’s crippled energy infrastructure continuing to dominate the headlines, it’s important to revisit our outlook for crude oil, natural gas and NGLs.

An update on the various E&P stocks featured in the model Portfolios. See The Producers.

Want to know which stocks to buy now? Check out the Fresh Money Buys list. See Fresh Money Buys.

The Stocks

Halliburton (NYSE: HAL)–Hold in Energy Watch List
Weatherford International (NYSE: WFT)–Buy < 28
Schlumberger (NYSE: SLB)–Buy < 100
EOG Resources (NYSE: EOG)–Buy < 125
Afren (LSE: AFR, OTC: AFRNY)–Buy < GBp175
Oasis Petroleum (NYSE: OAS)–Buy < 36
Suncor Energy (TSX: SU, NYSE: SU)–Buy < USD48
Petrohawk Energy Corp (NYSE: HK)–Hold
Range Resources Corp (NYSE: RRC)–Hold

Commodity Update

How our favorite E&P names fare in 2011 hinges in part on the pricing environment for the energy commodities they produce. With the civil war in Libya and Japan’s crippled energy infrastructure continuing to dominate the headlines, it’s important to revisit our outlook for crude oil, natural gas and NGLs.

Crude Oil

In Road Map for 2011, I predicted that oil would top $100 per barrel early in the new year and breach $120 per barrel at some point in 2011. As of April 4, when Brent crude oil closed the trading session at $121.06, both forecasts had come to fruition, albeit far sooner than we had anticipated at the beginning of the year. Although West Texas Intermediate (WTI) crude oil–the US benchmark–has yet to eclipse $110 barrels in 2011, this incongruity stems from a regional oversupply of crude oil in Cushing, Okla. This year the market has focused on Brent crude oil, which better reflects global supply and demand conditions.

Oiling Up and Going Nuclear, published on March 2, 2011, warned of a potential short-term correction in oil prices. In mid-March, WTI dipped below $100 a barrel for a few days, while Brent fell to less than $110 per barrel. With WTI now trading at $108 per barrel and Brent above $120, this correction was much milder than expected.

The call for a short-term pullback in oil prices hinged on two predictions: that the civil unrest spreading in the Middle East and North Africa wouldn’t bring down the Saudi government; and that a short-lived conflict in Libya would disrupt about two-thirds of the country’s oil exports.

Hindsight is 20-20. As predicted, protests in Saudi Arabia failed to achieve critical mass. A mid-March “Day of Rage” fizzled, and demonstrations in the country’s Shiite-dominated eastern provinces were quickly subdued. The Saudi government will also plowed roughly 25 percent of the country’s gross domestic product into social programs over the next few years, including initiatives to encourage homeownership, create 60,000 new security jobs, raise the minimum wage, support the unemployed and build hospitals.   

Much of the unrest in Saudi Arabia springs from a basic conflict between the Sunni majority and the Shia minority. Unemployment rates are generally higher in the Shia-dominated portion of the country, so the governments recently announced spending packages should benefit the minority disproportionally. These social investments, the monarchy’s legitimacy with a large part of the population and a heavy security presence are powerful stabilizing forces.

Despite recent unrest in Yemen and Bahrain, investors shouldn’t worry that civil unrest will disrupt Saudi oil exports.

The conflict in Libya has worsened considerably over the past month. In the early days of the civil war, anti-Qaddafi forces appeared to have the upper hand, capturing several key cities and making incursions into the western half of the nation where Qadaffi’s power base lies.

But forces loyal to Qaddaffi recaptured lost ground in mid-March and appeared poised to capture the eastern city of Benghazi, a stronghold for the opposition. At that point, the allied air campaign against Qaddaffi’s forces helped turn the tide once again.

Nearly three weeks after the start of the air campaign, the conflict appears no closer to being resolved; neither side has made much headway. Meanwhile, Libyan oil exports have been far more severely impacted than most had expected.

Source: Bloomberg

The best estimates suggest that Libyan oil exports averaged less than 400,000 barrels per day in March, down nearly 80 percent from 1.6 million barrels day before the conflict began. This situation continues to deteriorate.

On April 5, 2011, opposition forces managed to load a Swiss-owned tanker with about 1 million barrels of light, sweet crude oil for shipment to an unknown buyer. This cargo was loaded at the Tabrouk terminal in eastern Libya, an area that the opposition has controlled since the conflict’s early days.

Subsequent reports indicate that Qaddaffi’s forces attacked a pumping station that sends oil via pipeline to Tobruk, limiting the likelihood of future exports. Tobruk isn’t the only facility that’s been damaged; pipelines Es Sider, the nation’s largest terminal, are also bombed.

Libya boasts nine major terminals, five of which are located in the heart of opposition territory and have a total export capacity about 850,000 barrels per day. The remaining four ports are in the western half of the country–Qadaffi’s stronghold–have a total capacity of about 450,000 barrels per day.

Most of Libya’s major oilfields are located in the east, though damage to the country’s energy infrastructure should restrict exports. The vessel loaded on April 5 likely carried stored oil that had been produced before the civil war picked up.

In short, the ongoing civil war and Libya’s crippled energy infrastructure mean that the country’s limited oil exports will remain spotty for some time.

Saudi Arabia and other OPEC members have stepped into the breach, pumping enough oil to offset the loss of Libya’s light, sweet crude. According to the International Energy Agency (IEA), the Saudis have blended different grades of crude oil to create a product that more closely approximates Libyan production.

Source: Bloomberg

This graph tracks oil output from Kuwait, Saudi Arabia and the United Arab Emirates (UAE), all three of which have ramped up their output.

As expected, the Saudis have led the way, in March pumping 750,000 barrels per day more than in December 2010. The UAE has chipped in roughly 200,000 extra barrels per day, while Kuwait has flowed an extra 100,000 barrels per day.

After these increases, Kuwait and the UAE have little spare capacity. Saudi Arabia, on the other hand, is estimated to have another 2.5 million barrels of oil per day that it can bring online. Though these moves offset lost Libyan supply, oil prices tend to rise when OPEC taps its spare capacity. Check out the graph below.

Source: Bloomberg

Saudi Arabia accounts for 70 to 80 percent of OPEC’s spare capacity, making the country a good proxy for the rest of the cartel. When Saudi spare capacity tightened from mid-2007 to mid-2008, crude oil prices rallied to almost $150 per barrel in summer 2008.

The country’s spare capacity increased from fall 2008 to mid-2009, after oil demand collapsed amid the financial crisis and global economic slowdown. When OPEC output declines, these idled fields count as spare capacity.

More recently, Saudi spare capacity increased from late 2009 to mid-2010. Unlike prior cycles, this growth didn’t stem from demand destruction; the Saudis completed new projects that increased the nation’s oil production capacity.

If history is a guide, the recent drawdown in OPEC spare capacity should support oil prices.

Oil prices could suffer a short-term correction in coming months, especially if the conflict in Libya appears headed toward a resolution.

A global recession would also jeopardize the rally in oil prices, which is what occurred when oil prices tumbled precipitously in fall 2008. Some pundits have argued that sky-high oil prices caused the 2007-08 recession, but that narrative conveniently ignores the credit crunch touched off by the US residential mortgage crisis. Regardless, a recession doesn’t appear to be in the cards at this point; economic data from the US and other major markets remain robust.

In the March 25, 2011, issue of The Energy Strategist Weekly, Energy Costs and Energy Policy: Advantage USA, I explained why the US economy is less vulnerable to higher oil prices than many other countries. But at these levels, the price of Brent crude is high enough to cause demand destruction in Europe. If oil prices remain elevated, the IEA will likely scale back its forecast for growth in global oil demand. Any moderation in demand growth would prevent oil prices from spiking too far above current levels.

Recent developments suggest that oil prices will easily average more than $100 per barrel in 2011. Investors also shouldn’t rule out a move to $140 per barrel at some point this year–a price point I had expected in 2012. I see a 50-50 chance that oil breaches $140 per barrel in 2011. As before, Brent crude oil will lead any rallies; WTI should continue to trade at a discount to Brent for the foreseeable future. But don’t expect Brent crude oil to remain above $120 per barrel for a prolonged period, as demand growth would suffer.

Contrary to popular belief, sky-high oil prices aren’t welcome news for energy producers, oil services companies and other stocks in the group. Although profits may jump in the short term, inordinately high oil prices tend to erode global demand and set the stage for a correction. Producers would prefer that oil prices hover around $100 per barrel, a sustainable level that generates solid profits and encourages drilling activity. Fears of demand destruction are one of the main reasons energy stocks fall or rally only slightly when oil prices jump.

Drilling activity is already on the rise, particularly in the Middle East. Saudi Arabia plans to increase its rig count by about one-third by the end of 2011. Shares of Halliburton (NYSE: HAL) recently received a lift after reports circulated that the Saudis plan to increase spending in the Manifa oil field. Halliburton continues to rate a “hold” in the Energy Watch List because of my ongoing concerns about its exposure to a weakening North American pressure pumping market.

Wildcatters Portfolio Holdings Schlumberger (NYSE: SLB) and Weatherford International (NYSE: WFT) stand to benefit more from an uptick in Mideast drilling activity. Each company generates about one-quarter of its revenue from the Middle East and has less exposure to the North American market than Halliburton.

As drilling activity picks up over the next quarter or two, Schlumberger and Weatherford International could regain pricing power–a major potential upside catalyst the stocks. Buy Weatherford International under 28. Schlumberger rates a buy under 100.

Natural Gas Liquids

Natural gas is composed primarily of methane, a hydrocarbon consisting of one carbon atom bound to four hydrogen atoms (CH4). But methane typically occurs with a variety of heavier hydrocarbons (NGLs), such as ethane (C2H6), propane (C3H8) and butane (C4H10). Crude oil, water vapor, carbon dioxide, nitrogen and sulfur also mix with raw natural gas.

The components of this mélange vary from field to field. Some regions produce “dry” natural gas, or gas that consists primarily of methane with little NGL content. In contrast, “wet” fields such as the Eagle Ford of Texas and the Marcellus Shale in Appalachia also contain large quantities of NGLs.

NGLs may not receive as much media attention as crude oil or natural gas, but they’re vital energy commodities. Ethane and propane are commonly used as petrochemical feedstock. Ethane is used to make ethylene, while propane is used to manufacture propylene–chemicals that form the building blocks of various plastics. Oil refineries also use NGLs to boost the octane rating of gasoline.

Historically, a barrel of NGLs sells for roughly 60 to 65 percent of a barrel of WTI crude oil, though at times the pricing relationship deviates from this long-term average.

Over the past 12 to 18 months, a barrel of NGLs has traded at a larger than average discount to crude oil.

Source: Bloomberg

The current price of a barrel of mixed NGLs delivered to the Henry Hub is $59 per barrel, compared to about $108 per barrel for WTI. In other words, the price ratio between a NGLs and WTI has declined to roughly 55 percent–off the long-term average but roughly consistent with the past 18 months.

More important, compare the price movements of individual NGLs to those of crude oil and natural gas. The data in this graph converts the 12-month strip–the average price of the next year’s worth of natural gas futures–into barrels of oil equivalent for comparison with NGLs and WTI.

As you can see, NGL prices continue to track the price of oil far more closely than the price of natural gas. The only potential exception to that rule is ethane, the most common NGL. But, ethane prices have trended higher since last summer, while gas prices have drifted slightly lower. Moreover, for much of the past two years, ethane has traded at a discount to natural gas; now it commands a premium.

The relationship between oil and NGLs has broken down of late because of surging NGL production from US shale fields. 

Source: Energy Information Administration

Many of the best unconventional gas fields in the US, including the Marcellus Shale and the Eagle Ford Shale, coproduce large amounts of NGLs.

Despite the surge in NGL production, prices remain attractive compared to natural gas, largely because the US has exported some of this output and domestic consumption has increased–several major petrochemicals plants have opened or been restarted over the past 18 months.

Although robust supply growth in the US and Canada will keep the ratio of NGL to oil prices below the long-term average, liquids will still be far more valuable than natural gas. Investors must distinguish between producers that operate in wet gas fields and those that target dry gas; E&P firms with exposure to liquids-rich plays enjoy superior economics.

Natural Gas

It’s trite to say that a picture is worth a thousand words. But that’s absolutely the case when it comes to the global natural gas markets. Here’s the picture investors should watch.

Source: Bloomberg

This graph juxtaposes the price of natural gas futures traded in the US against London-traded futures. The near-month futures contract for US natural gas trades at $4.15 per million British thermal units (BTU), while the equivalent UK-traded futures contract goes for USD11.22 per million BTUs. The price of gas in Europe is close to three times the price of gas in the US right now.

The US is the world’s largest gas producer, annually extracting almost as much gas as the Middle East and Africa combined. North America is essentially a self-contained market, with the US and Canada supplying enough gas to meet their domestic needs. Although the US doesn’t need to import liquefied natural gas (LNG) from abroad, it does function as a market of last resort for companies with unplaced LNG cargoes, largely because of its storage capacity.

At the same time, the US has only one LNG export facility in Alaska. The more than a dozen LNG import terminals pre-date the shale gas revolution, which transformed the US market from one characterized by a shortage of supply to one glutted with natural gas.

A number of companies have filed permits to add export capacity to existing LNG import terminals, but these capital-intensive projects are years from completion.

Over the past week, much has been made of President Obama’s Remarks on America’s Energy Security, a speech delivered at Georgetown University on March 30 that highlighted natural gas as a crucial component of the nation’s energy independence. This excerpt demonstrates why shares of natural gas producers and names related to natural gas-fueled vehicles have soared:

[T]he potential for natural gas is enormous. And this is an area where there’s actually been some broad bipartisan agreement. Last year, more than 150 members of Congress from both sides of the aisle produced legislation providing incentives to use clean-burning natural gas in our vehicles instead of oil. And that’s a big deal. Getting 150 members of Congress to agree on anything is a big deal. And they were even joined by T. Boone Pickens, a businessman who made his fortune on oil, but who is out there making the simple point that we can’t simply drill our way out of our energy problems.

So I ask members of Congress and all the interested parties involved to keep at it, pass a bill that helps us achieve the goal of extracting natural gas in a safe, environmentally sound way.

In this speech, the president effectively endorses billionaire T. Boone Pickens’ plan to incentivize the use of natural gas as a transportation fuel.

Although the president’s comments are encouraging, talk is cheap. An energy bill that encouraged the use of natural gas as a transportation fuel could win bipartisan support, but most politicians are focused on the budget, a potential government shutdown and the looming 2012 presidential race.

Even a bill modeled after the Pickens Plan passed the House and Senate, converting trucks to run on natural gas would take time. Regardless, Obama’s recent comments won’t provide a near-term release valve for the oversupplied US natural gas market. Natural gas prices will remain depressed in this country until producers scale back production; the pricing environment is unlikely to improve in 2011.

The outlook for global gas prices could not be more different. Rising demand from Asian emerging markets and from Japan in the wake of the earthquake should tighten global LNG markets. Meanwhile, European LNG imports will pick up as an alternative to Russian gas and in Germany, which has accelerated plans to reduce its dependence on nuclear power. (See The Fallout.)

The Producers

Most investors gravitate toward E&P companies when they consider buying energy stocks, likely because the business is relatively simple: E&P firms explore for new fields and produce oil and natural gas.

Given my outlook for oil, natural gas and NGL prices, investors should favor names with liquids-rich production profiles. A key consideration when evaluating a producer’s growth prospects is the extent to which the firm will be able to expand its output over time. Stocks in this subsector exhibit a strong correlation between production growth and shareholder returns

The quality of a producer’s reserve base is essential to assessing whether its stock is a worthwhile investment. At present, I prefer companies with exposure to fields such as the Bakken Shale of North Dakota and Montana and the Eagle Ford Shale of Texas. These plays have yielded a steady stream of prolific wells, and companies with solid acreage positions in these regions have the scope to grow their output at a rapid clip. Here’s an update on the independent producers featured in the model Portfolios.

EOG Resources

Shares of Wildcatters Portfolio holding EOG Resources (NYSE: EOG) recently rallied to a 52-week high amid optimism about the company’s potential to grow its oil production over the next few years. EOG has amassed a leading position in some of the hottest onshore unconventional oil reserves in the US.

An early mover, the company amassed acreage in the sweet spots of the Eagle Ford and other fields before these plays were widely known and well-understood. As a result, EOG has assembled its drilling portfolio at attractive prices and now earns impressive returns on these investments. Companies that were late to the party ended up paying much higher rates for quality acreage or were forced to lease less-productive land on the periphery.

After the stock’s recent run, it’s easy to forget that shares of EOG were slammed in November 2010, when management scaled back its full-year 2010 production growth estimate to 9 percent from 13 percent. The company also trimmed its forecast for 2011 production growth to 10 percent and its 2012 estimate to 12 percent. At its analyst day in April 2010, management had projected output growth of more than 20 percent for each of the next two years.

The stock’s quick rebound from this disappointing news serves as a reminder of why it pays to take the long view when a company experiences a temporary setback.

In a Nov. 5, 2010, Flash Alert, we reiterated our “buy” rating on EOG and noted that the market had overreacted to the company’s lowered production guidance. The unexpected production shortfall had nothing to do with the quality of EOG’s resource base, but rather the availability of hydraulic fracturing and other key services.

Two technologies have revolutionized the production of oil and natural gas from shale fields in North America: horizontal drilling and hydraulic fracturing. Horizontal drilling involves sinking a vertical well to a particular depth and then drilling sideways. By drilling horizontally, producers expose a larger portion of their wells to the most productive parts of the field.

Oil and natural gas aren’t found in giant underground caverns or lakes; these hydrocarbons are locked in the pores and crevices of a reservoir rock. The hottest unconventional fields such as the Eagle Ford and the Bakken Shale of North Dakota and Montana contain plenty of oil. However, that crude can’t flow into a well because the pores of the reservoir rock aren’t interconnected.

To remedy that problem, producers pump a mixture of primarily water and sand into the field. The pressure literally cracks the reservoir rock, providing paths through which hydrocarbons can flow. The sand, or proppant in industry parlance, props open the fissures created during hydraulic fracturing.

The rapid development of a number of shale plays over the past two years has led to an acute shortage of pressure pumping capacity. Producers have to wait months for drilled wells to be fractured and prepared for production. The lack of sufficient fracturing capacity–not poor reserve quality–was behind EOG’s lowered production guidance.

Investors who sold in a panic or set trailing stop-loss orders liquidated their positions at fire-sale prices. In contrast, level-headed investors who took the time to realize that EOG’s production shortfall wasn’t a company-specific issue were able to buy the stock at bargain prices.

Oil and LNG Growth

EOG’s fourth-quarter results and 2011 production guidance illustrate the quality and potential of the firm’s fields. The company has spent the past five years concentrating the majority of its drilling activity and capital spending on the production of oil and natural gas liquids (NGL) such as ethane, propane and butane. Natural gas, which currently trades at depressed prices in the US, is more of an afterthought.

With oil prices at elevated levels, the company’s growing exposure to crude oil has paid off.

Source: EOG Resources

In the fourth quarter of 2010, high-value oil and NGLs accounted for roughly three-quarters of the company’s revenue. This percentage will continue to expand, with 80 percent of planned 2011 capital spending directed at liquids-rich fields. Management expects the company’s oil production to grow by 55 percent in 2011. Meanwhile, the company forecasts a 34 percent increase in NGL production.

The Eagle Ford should contribute the most to EOG’s production growth in 2011. Management reported drilling results from several wells located in the core oil-rich window in the northern part of the field. All of those wells showed initial production rates of between 1,200 and 1,800 barrels per day, results that were unheard of only a few years ago. EOG spends about $6 million to drill a well in the Eagle Ford, but management aims to reduce that cost to about $5 million. At that price, EOG would generate returns on investment as high as 125 percent.

The biggest challenges to meeting these goals appear to be a shortage of proppant and a lack of sufficient pipeline infrastructure to move oil out of the region. EOG has contracted with Proven Reserves Portfolio stalwart Enterprise Products Partners LP (NYSE: EPD) to secure capacity on a pipeline that the master limited partnership is building. In the meantime, the firm will use trucks to transport crude from the region.

In its most recent conference call, management noted that the company has resolved the issue of insufficient fracturing capacity that caused it to lower production guidance last year. Although management declined to elaborate on this solution, the firm likely set up a long-term arrangement with one or more of the major services firms. At any rate, the firm beat the production growth targets it provided in November 2010, suggesting that management’s new guidance is achievable.

EOG also has a substantial presence in the Bakken Shale, which is still the biggest contributor to its overall production. Management also claims that the company is the largest oil producer in North Dakota. Lately, EOG has been doing a lot of testing on some of its acreage outside the plays established core, especially along the border between North Dakota and Montana. Two recent wells produced at an initial rate of 1,458 and 1,882 barrels of oil per day, respectively. That’s not as good as the initial production rates EOG and others have recorded in the Bakken’s core, but it’s sufficient to yield internal rates of return of about 50 percent. 

The company boasts longer-term growth opportunities in several new fields, including the Wolfcamp play in the Permian Basin and the Niobrara field in the Rockies.  

The Permian Basin is located in western Texas and New Mexico. EOG drilled its first well there in early 2009 .and has now drilled and completed a total of four. These wells produce a liquids-rich combination of 55 percent oil, 23 percent NGLs and just 22 percent natural gas. The company has amassed 120,000 acres in the region.

The Niobrara is located in Colorado and has received a lot of attention lately. The field remains in the early stages of development. EOG has plans to drill about 40 wells in 2011 to prove the value of its acreage position there. Early results have been positive, with wells offering initial production rates in the range of 700 to 850 barrels of oil per day.

EOG’s most exciting opportunity in natural gas is the Kitimat liquefied natural gas (LNG) export terminal it’s building with Apache Corp (NYSE: APA) in British Columbia. LNG is super-cooled natural gas that can be shipped via special tankers.

The Kitimat partners are looking to negotiate a long-term, oil-indexed LNG supply agreement with an Asian buyer. A few months ago, such a contract would have been difficult to secure because of weak LNG prices. But the devastating earthquake and tsunami knocked out a sizable portion of Japan’s nuclear power capacity, damage that will force the island nation to increase LNG imports. 

In addition, Germany’s rash decision to shutter seven of its older nuclear plants and shut down all of its plants by 2022 will result in sharply higher demand for LNG in Europe. EOG Resources rates a buy up to 125.

Suncor Energy

By the end of this decade, Suncor Energy (TSX: SU, NYSE: SU) expects its Canadian oil sands division to account for three-quarters of the firm’s total cash flows. The remaining third will come from its offshore and international operations.

Management has set forth an aggressive plan for production growth, targeting 1 million barrels per day in annual output by the end of the decade. This goal implies annualized production growth of 8 percent over the next decade. Most of the growth will come from its oil sands operations, which management expects to grow its output at a 10 percent annualized rate.

Another major advantage for Suncor is that more than 90 percent of its total production is oil, not natural gas or NGLs. Over the past year, the firm has disposed over more than $3.5 billion worth of noncore assets, including a number of gas-producing properties. In the current environment of high international oil prices and weak US gas prices, Suncor’s oil-heavy portfolio is a winning bet.

Management recently finalized an agreement on a strategic joint venture with France-based integrated oil giant Total (NYSE: TOT).  Under the terms of the deal, Suncor swapped a 19.2 percent stake in its Fort Hills oil sands production project for a 36.75 percent stake in Total’s Joslyn project in Canada. Total, an experienced player in the oil sands in its own right, will continue to operate the Josyln project; Suncor will continue to run the Fort Hills project.

Suncor also sold a 49 percent stake (retaining the majority) in its Voyageur upgrader in Canada. Production from oil sands mining projects consists of a product known as bitumen, an extraordinarily heavy, viscous hydrocarbon. Bitumen trades at a sizeable discount to crude oil because it’s tougher to refine and requires expensive treatment before it can be converted into refined products such as gasoline or jet fuel. An upgrader can convert bitumen into synthetic crude oil, a product that is similar to standard light, sweet crude oil. As you might expect, synthetic oil trades at a substantial premium to bitumen.

The Voyageur upgrader will ultimately have capacity of about 200,000 barrels per day (102,000 barrels per day for Suncor’s share), and is expected to be put into service by 2016. Upgraders are a key part of the oil sands production process, but are also extremely expensive to build. By partnering with Total–a company nearly twice Suncor’s size–the firm company reduces its capital commitments. All told, Suncor picked up USD1.75 billion in cash and about 160 million barrels in high-quality oil sands reserves from the joint venture with Total.

To meet its ambitious production goals, Suncor has announced eight major projects that will take place in the oil sands.

Source: Suncor Energy

Like any other major mining project, oil sand projects are subject to delays from time to time; however, the addition of Total as a partner increases the chances Suncor will complete projects on schedule. Meanwhile, near-term projects–including Firebag 3 and 4–appear to be progressing according to management’s master plan. In 2011 the company aims to grow its oil sands output to as much as 310,000 barrels of oil per day, up from about 280,000 barrels per day in 2010.

Suncor’s stock took a hit recently because of its operations in Libya. Suncor in late February announced in late February that it had shut in all of its production in Libya and evacuated its staff to Malta.

While any exposure to Libya makes for a bad headline, the operation contributed only 35,000 barrels of oil per day to total production–a significant amount, but small in comparison to its oil sands output.

The main driver of Suncor’s growth and its main attraction for investors’ lies in the Canadian oil sands, not in Libya. Take advantage if the recent pullback and buy Suncor Energy under USD48.

Oasis Petroleum

We first profiled Oasis Petroleum (NYSE: OAS) in the Jan. 19, 2011, issue Small is Beautiful. Our general take on the company hasn’t changed appreciably since then.

Oasis’ only area of operation is the Bakken area of North Dakota and Montana, one of the hottest and fastest growing unconventional oil producing regions in the US. Oil accounts for more than 90 percent of the company’s production profile. The company operates in two regions: the West Williston, located along the border of Montana and North Dakota, and the East Neeson, located to the east in North Dakota.

The West Williston contains is the more prolific of the two–wells in this region produce at a rate of 415 to 708 barrels of oil per day in their first 60 days of production, compared to a range of 386 to 611 barrels per day in the Neeson. Oasis estimates that ultimately recoverable reserves from a well in the West Williston are 400,000 to 700,000 barrels of oil. That’s compared to 350,000 to 600,000 on its eastern play. Nonetheless, both the West Williston and Neeson offer attractive returns on investment, particularly at current oil prices.

Oasis is a small company in the early stages of a multiyear growth program. At the end of 2010, the company produced about 7,511 barrels per day from its wells. Management forecasts production of 11,000 to 12,500 in 2011, more than two times its average production in 2010.

To facilitate this growth, Oasis has boosted its planned capital spending budget to $490 million in 2011, up more than 40 percent from 2010. The company plans to focus more than 80 percent of that budget on its fields in the West Williston, where six of its seven rigs will operate. Finally, the company plans to drill 69 operated wells in 2011, compared to just 26 in 2010.

Management offered a few tidbits about some of Oasis’ recent well results during a conference call to discuss fourth-quarter earnings. Specifically, management highlighted its success in the Indian Hills portion of the West Williston. Wells in this region are apparently deeper and have higher geologic pressures, which increases initial production rates. In addition, management noted that the reservoir rocks have greater porosity. Because of these favorable characteristics, wells in this region perform far better than the average well in the West Williston area. Oasis has 23,000-acre leasehold in Indian Hills, and plans to spend about 20 percent of its total 2011 capital budget on drilling this acreage. 

The firm’s largest position in the West Williston is the Red Bank region. This area isn’t as productive as Indian Hills, but the wells have performed performed in line with average for the region.

Oasis continues to experiment with other means to increase production other than simply drilling more wells; for example, the company is testing 36-stage fracturing jobs. It’s a bit early for management to gauge results, but it appears that the additional cost of performing a larger fracturing job is offset by higher production and reserve bookings.

The post-earnings dip in the stock price likely reflects profit-taking after a substantial rally. A fast-growing producer in a red-hot play, Oasis Petroleum rates a buy under 36.

Afren

Shares of London-headquartered Afren (LSE: AFR, OTC: AFRNY) have been on a roll recently, rallying 90 percent since last August. The stock headed even higher after reporting its full-year results in late March. Afren is a direct play on one of the world’s fastest-growing oil and gas-producing regions: Africa.

In 2010 the company produced an average of 14,330 barrels per day; the company’s 2011 guidance calls for output expects to grow almost 190 percent to 40,000 barrels per day. Over the past year, the company has also expanded from a handful of interesting plays in West Africa to 11 countries across the continent, including operations in Ethiopa, Kenya, Madagascar and the Seychelles Islands.

The company’s biggest producing fields are the Okoro and Ebok fields in the shallow water off the coast of Nigeria. Both fields were originally discovered and tested by major oil companies, but they’re both relatively small. These fields were already known producers and there was already some technical information available when Afren bought their rights.

Okoro and Setu a smaller field nearby, produce about 16,055barrels per day of oil. Afren plans to drill two additional wells in 2011m adding another 3,000 to 5,000 barrels of oil equivalent output to that total. Both wells are infill projects–that is, Afren is drilling a new well in an area known to be productive. In this instance, there’s little risk of sinking a dry hole.

Ebok is located in 135 feet of water off the coast of Nigeria. Afren is producing this field in two stages: phase 1 drilling should be completed in late 2010, while phase 2 drilling will be completed over the course of the second quarter. In February, Afren installed production, processing and storage facilities on the play and began producing the field. Phase 1 is expected to come in ahead of the company’s original targets, producing more than 15,000 barrels per day. The second phase should add 20,000 barrels of oil per day to that total,bringing the entire field production to about 35,000 barrels per day day. There are opportunities for Afren to expand production even further by drilling additional infill wells in the play and adding phases to the to the Ebok field development plan.

About 8 miles offshore the Cote d’Ivoire, Afren produces natural gas and oil from the Lion and Panthere fields in waters ranging from 150 to 900 feet deep. Total production is 5,088 barrels of oil equivalent per day and comprises 1,086 barrels day of oil and 23.2 million cubic feet of natural gas. The company also owns a gas processing plant that extracts NGLs from gas produced in the field.

The Cote D’Ivoire hasn’t been the most politically stable country, but it helps that Afren’s producing fields are offshore. As of the end of March, the company indicated that all of its operations at the gas plant and fields are operating normally. This is an issue that bears watching, but political risks are part and parcel with investing in Africa.

In addition to ramping up production from existing fields, Afren is also doing considerable appraisal and development work. In Nigeria, the firm is drilling wells to evaluate the productivity of the Okwok field, located in the same basic area as Ebok. The company’s Okwok-9 appraisal well encountered a 35-foot interval of crude oil and solid reservoir characteristics.  Based on these tests, Afren believes a horizontal well similar to what it’s drilling in Ebok could generate production of 2,000 to 4,000 barrels per day.

The company’s CI-01 field in Cote D’Ivoire lies on the maritime border with Ghana. That puts it adjacent to some truly massive offshore discoveries in recent years. At this point, Afren is mainly doing seismic work on the play and may look to take on a partner to reduce development and appraisal costs.

Afren’s exploration projects are too numerous to cover at depth. Suffice it to say that it’s performing seismic work and planning exploration drilling in all 11 countries in which it currently has drilling rights. Although you shouldn’t expect much near-term production from any of these fields, what really gets Afren’s stock moving is news about successful well results from exploratory wells. Expect to hear a great deal on that front over the next year.

Despite the big run-up in the stock, Afren only trades for around 8.5 times this year’s projected earnings. That valuation is more than reasonable when you consider the firm expects to more than double its output in 2011 and has significant exploration upside. Afren rates a buy under GBp175.

Please note that stocks traded on the London Stock Exchange don’t trade in British pounds sterling but in pence (1/100 of a pound). For example, at the close of London trading on April 5, Afren closed at GBp170, or GBP1.70 (roughly USD2.77 at current exchange rates).

Afren also trades as an American depositary receipt (ADR) in the US. Each ADR represents ownership of riv3 London-traded shares. It’s best to buy the stock in London; trading volumes are much higher there. If not, Afren’s ADRs are a buy under USD14.50. 

Thus far, 2011 has been kind to the model Portfolios’ two natural gas producers.  Shares of Gushers Portfolio holding Petrohawk Energy Corp (NYSE: HK) have returned 34.5 percent this year, while shares of Range Resources Corp (NYSE: RRC), a member of the Wildcatters Portfolio, are up 30.9 percent.

This recent strength stems from an influx of cash from value-oriented investors that began in fall 2010, after share prices bottomed amid concerns about depressed natural gas prices in North America. Although some of this upside was justified–an increasing focus on fields rich in NGLs and condensate should improve the revenue mix in 2011–momentum traders have sent these stocks to prices that don’t reflect underlying fundamentals.

Investors have a handful of reasons to be bullish. For one, over the past six months, Baker Hughes’ natural gas-directed rig count has declined from a high of 971 during the week of Oct.10, 2010, to 891 during the week of April 1, 2011. Moreover, reports from natural gas producers suggest that drilling activity in dry-gas plays will continue to fall as operators focus on the Eagle Ford and other liquids-rich plays.

But US production is unlikely to decline meaningfully in 2011, as a backlog of hydraulic fracturing jobs on previously drilled wells should offset scaled-back activity in dry-gas fields.

Shares of natural gas producers also jumped after President Obama spoke about the importance of the fossil fuel to the nation’s energy security and the Environmental Protection Agency announced a final rule easing the conversion of cars and trucks to run on compressed natural gas. Although both of these developments are encouraging, neither suggests that the demand side will furnish much relief in the near term.

Plans to ramp up US exports of liquefied natural gas to Asia likewise won’t provide a release valve for the current supply overhang; not only must plans to add export capacity to existing import terminals gain regulatory approval, but the capital-intensive nature of these projects pushes the potential completion dates out even further.

Short of the industry reining in drilling activity, US natural gas prices should remain depressed through 2011. Shares of Petrohawk Energy and Range Resources remain at risk of a correction as long as the industry’s fundamentals remain weak.

That being said, both stocks continue to rate a hold for investors with a longer time horizon. With exposure to the sweet spots in some of the nation’s most prolific unconventional gas plays, Petrohawk Energy and Range Resources would benefit inordinately from a recovery in natural gas prices. Here’s a rundown on each company’s assets and growth strategy.

Petrohawk Energy Corp

An early entrant in the Haynesville Shale of Louisiana and the Eagle Ford Shale in south Texas, Petrohawk Energy has amassed high-quality acreage positions in both plays. But the company’s astute management team is an equally important asset to shareholders.

For many gas-focused exploration and production firms, 2010-11 marks an important transitional period that will separate the long-term winners from the losers. With an oversupply of natural gas continuing to depress prices, Petrohawk Energy has focused on shoring up its balance sheet by divesting nonessential assets, increasing the liquids content in its production mix and securing leaseholds in the sweet spots of its core plays.

To this end, the company sold its acreage and midstream assets in Arkansas’ Fayetteville Shale to XTO Energy, a subsidiary of ExxonMobil Corp (NYSE: XOM), for $650 million. Management indicated that the proceeds from this transaction will be plowed into the company’s 2011 capital budget, with the goal of more than doubling its NGL, condensate and oil output to 12 percent of total production. Management estimates that 30 percent of the company’s acreage is prospective for NGLs, condensate or crude oil.

If the company meets its 2011 production guidance, liquids would account for 27 percent of revenue, a substantial uptick from 2010.

Source: Petrohawk

Although management didn’t provide specific numbers, CEO Floyd Wilson did offer the following advice during the company’s conference call to discuss its 2010 operational update:

We’re not really giving guidance for [2012] and ‘[2013], but…we’ve really ramped up our activities and we’re getting a lot more condensate and NGLs out of these wells than we used to project. So…you know the number really continues to increase for a couple of years.

This shift will begin in the back half of 2011, when management expects the company to have secured all of its core leaseholds in the Haynesville by production. Not only will that enable Petrohawk Energy to reduce drilling activity in this prolific dry-gas field, but management will also be able to allocate more capital to its operations in the liquids-rich Eagle Ford Shale. In the final six months of 2011, the company will reduce its rig count in the Haynesville to seven from 16. In 2010 the firm sank 351 wells in the Haynesville Shale, 101 of which it operated; in 2011 Petrohawk Energy expects to drill 88 wells in the play–57 in the first half of the year and 31 in the back half.

As part of its strategic plan, Petrohawk Energy will let the leases on 135,000 acres of its noncore Haynesville territory expire, leaving it with about 225,000 acres, of which it operates about 75 percent. 

Since Petrohawk Energy began drilling in the Haynesville, the company has focused on honing its drilling techniques to reduce costs and improve estimated ultimately recoverable (EUR) natural gas. Its engineers discovered that restricting flow rates both reduces production costs and increases EUR by an average of 2.5 billion cubic feet (Bcf). In 2012-13, after Petrohawk Energy secures its leasehold in the Haynesville, the company has the option to begin full-scale production. Using multi-well pads would reduce expenses substantially–management pegs costs in the Haynesville at $10.6 million per well–reducing the down time between wells and the cost of relocating equipment between drilling sites.

Management also indicated that Petrohawk Energy would likely sell its 50 percent stake in the KinderHawk, one of the largest gathering and processing systems in the Haynesville, or spin the operation off as a master limited partnership. 

Despite these potential cost improvements, the company’s Haynesville acreage represents a long-term opportunity, a reality that CEO Floyd Wilson emphasized during the company’s conference call to discuss fourth-quarter earnings:

Incidentally, the NAVs for each of our core positions, the Haynesville/Bossier and Eagle Ford, in my opinion, have a greater value than where the market trades Petrohawk today. We really do look forward to the future…While we have a positive view of natural gas, I believe it to be a realistic view. We aren’t expecting the high prices of the past decade, nor are we expecting to have sub $4 gas forever. Our view is long term as are our assets.

In the near term, Petrohawk Energy will focus on ramping up its operations in the Eagle Ford Shale, a play the company discovered in 2008. Over the past three years, the company has amassed about 357,000 commercially producible acres in the Eagle Ford. Its leasehold is located in three distinct areas: Hawkville, Black Hawk and Red Hawk.

In 2010 the company drilled 36 operated wells and five non-operated wells in Hawkville, a 225,000-acre play that comprises two distinct regions: one which contains dry gas and one which includes natural gas and condensate. Well costs in the region average $7.5 million per well. The five rigs that will operate in the region in 2011 will likely focus on the condensate-rich window. As part of an exclusive partnership with Wildcatters Portfolio holding Schlumberger, Petrohawk Energy began testing the services company’s HiWAY flow-channel hydraulic fracturing technique last fall. Early results suggest that this approach, which improves conductivity within in the reservoir rock, will elevate EURs.

The approximately 73,600-acre Black Hawk field, rich in NGLs and condensate, offers Petrohawk Energy the best returns in the current pricing environment. The company drilled 29 Black Hawk wells in 2010, generating an average of 385 barrels of condensate per million cubic feet (Mcf) of gas and 100 barrels of natural gas liquids per Mcf of gas. Management plans to sink 89 wells in 2011 in an effort to grow its liquids output.     

Red Hawk is an oil-prospective area where Petrohawk Energy has sunk five wells, two of which were awaiting completion as of March 30. One of these wells didn’t produce favorable results, but the Mustang Ranch “C” #1H has flowed crude oil at a rate that suggests EUR of 200,000 barrels. The company will drill five additional wells in this area at an average cost of $5 million per well.

Petrohawk Energy balances its prolific dry-gas assets in the sweet spot of the Haynesville Shale with growing liquids production from the Eagle Ford Shale. With a sound balance sheet and a plan to generate positive cash flow by 2013, Petrohawk Energy Corp continues to rate a hold.

Range Resources Corp

After announcing that its Barnett Shale operations were on the sales block in October 2010, Range Resources in February 2011 sold these assets to Legend Natural Gas IV LP for $900 million. Although CEO John Pinkerton acknowledged during the company’s conference call to discuss fourth-quarter results that this sales price “[was] roughly $200 million below his expectations,” he noted that the proceeds would enable the company to focus on securing its leasehold in Pennsylvania’s Marcellus Shale.

Pinkerton emphasized that despite giving up about 20 percent of its 2010 production in the deal, the firm expects to grow overall output by about 10 percent in 2011. Much of this production will come from increased drilling activity in the Marcellus Shale. With about 86 percent of the company’s $1.38 billion capital budget slated for drilling and completion in the Marcellus, management expects output from this field to double to roughly 400 Mcf per day in 2011.

This latest deal fits Range Resources’ established strategy of divesting higher-cost properties for lower-cost plays that offer superior growth potential. A longtime operator in Appalachia, Range Resources began drilling test wells in the Marcellus in 2004 and amassed a substantial acreage portfolio in both the NGL-rich window in Southwest Pennsylvania and the dry-gas window in the northeastern portion of the commonwealth.

Of the company’s Marcellus leasehold, management has identified 700,000 acres that it will seek to hold by production over the next few years. At present, Range Resources has secured about 46 percent of its leasehold by production; management expects to grow that proportion to 80 percent within the next two to three years.

As Pinkerton explained to analysts during the company’s conference call to discuss fourth-quarter results, selling the Barnett Shale assets to fuel growth in the Marcbriellus was a no-brainer:

It’s real simple to me: We have got drilling locations in the Marcellus that at $4.50 [per million BTUs] gas generate over a 50 percent return. Those same drilling locations in the Barnett are high-teens [offer] 20 percent type rates of return. So the question is pretty easy for me, not being the brightest bulb in the package. I’d rather spend the money in the Marcellus than the Barnett, so that’s why I sold the Barnett, pretty simple.

As an early mover in the play, Range Resources enjoys lower costs than many of its peers and has honed its production techniques over time. In fact, the company estimates that even with gas prices at $3.00 per million BTUs, wells drilled in the core dry-gas portion of the Marcellus Shale would still generate an internal rate of return of 10 percent.

The economics in the liquid-rich portion of the play are even more compelling. According to Range Resources’ most recent corporate presentation, wells in Southwest Pennsylvania yield an internal rate of return of 79 percent with gas prices at $5 per million BTUs. This return declines to 58 percent when gas goes for $4 per million BTUs.

As a further sweetener, management estimates that about 60 percent of the 700,000 acres it aims to hold by production overlap the Upper Devonian and Utica Shale, two natural gas-bearing zones in which Range Resources has sunk a handful of test wells.

Although Range Resources has focused much of its resources on the Marcellus, the firm also has exciting prospects in Virginia’s Nora Play, where it holds about 350,000 net acres, and in the Mid-Continent region of Texas and Oklahoma.

The low-cost producer in one of the nation’s most economic shale gas plays, Range Resources Corp continues to rate a hold.

Fresh Money Buys

The stocks recommended in the three model Portfolios represent my favorite picks. The three Portfolios are designed to target different levels of risk: Proven Reserves is the most conservative the Wildcatters names entail a bit more volatility; and Gushers are the riskier plays but have the most potential upside.

I realize that this long list of stocks can be confusing; subscribers often ask what they should buy now or where they should start. To answer that question, I’ve compiled a list of 18 Fresh Money Buys that includes 16 stocks and two hedges.

I’ve classified each recommendation by risk level–high, low or moderate–and included a brief rationale for buying each stock. Conservative investors should focus the majority of their assets in low- and moderate-risk plays, while aggressive investors should layer in exposure to my riskier and higher-potential plays. Hedges are appropriate for investors looking to offset exposure to energy stocks.

Also note that stocks that exceed my buy target for more than two consecutive issues will either be removed from the list or the buy target will be increased.

Source: Energy Strategist