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Riding the Services Cycle

By Elliott H. Gue on November 3, 2010

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Third-quarter earnings season is shaping up to be the fifth consecutive three month-period of better-than-expected results. Over 80 percent of S&P 500 companies that have reported thus far have trumped earnings expectations, and more than half of these companies exceeded estimates by more than one standard deviation. In other words, these firms didn’t top analysts’ forecasts by a penny or two–they completely blew away consensus estimates. Nearly two-thirds of the S&P 500 also beat revenue estimates.

Certain sectors stood out for their strong performance, namely energy and other groups with heavy exposure to emerging market demand. This trend bodes well for all of our Portfolio picks in 2011, but oil-services names remain one of my favorite plays; the next two to three years are shaping up to be the sweet spot of the group’s cycle.

In This Issue

The Stories

Third-quarter earnings and conference calls from the big oil-services firms suggest that the North American market will remain strong and international demand should improve in 2011. See The Big Picture,

Company-specific growth stories also remain intact in the oil-services industry. See Drilling Down.

Want to know which stocks to buy now? Check out the updated Fresh Money Buys. The table includes new buy targets for some of Elliott’s favorite plays. See Fresh Money Buys.

The Stocks

Halliburton (NYSE: HAL)–Buy in Energy Watch List
Schlumberger (NYSE: SLB)–Buy < 85
Weatherford International (NYSE: WFT)–Buy < 26

The Big Picture

One of the long-standing themes in this publication is “the end of easy oil.” The thesis is simple: The world is running out of easy and cheap-to-produce oil. With production from large, onshore fields declining, producers are increasingly turning to more complex fields such as deepwater  plays or the shale oil formations I covered in Rough Guide to Shale Oil.

Oil-services firms are arguably the purest play on this long-term trend. These outfits perform a wide variety of functions necessary to take a hydrocarbon play from discovery to production. Remember: The harder it is to produce oil from a given field, the more work there is for services firms. As exploration and production outfits increasingly focus on difficult-to-produce fields, services firms will reap the rewards.

Each quarter I pay particularly close attention to earnings releases from Halliburton (NYSE: HAL) as well as Portfolio holdings Schlumberger (NYSE: SLB) and Weatherford International (NYSE: WFT). By virtue of their size, these multinational operators offer a valuable bird’s eye view of both bigger-picture trends and the latest developments in key end markets.

Before delving into the particulars of each company’s third-quarter earnings release and conference call, let’s review a few broader trends that we’ll monitor into 2011.

North American Strength

In 2010 the US onshore rig count, which includes units drilling for oil or natural gas, has surprised most analysts to the upside, including myself. In general, greater the rig count, the stronger business conditions are for the major services firms. At the end of 2009, roughly 1,178 rigs were operating onshore in the US; the most recent data indicates that 1,672 such rigs are actively drilling for oil or natural gas.

Some additional background will put these numbers into context. Undercut by a broad collapse in oil and natural gas prices, the US onshore rig count dropped precipitously in late 2008 and early 2009, bottoming at 876 rigs in mid-June 2009. In less than a year and a half, the US rig count has almost doubled.

Two important trends are underway: a shift in drilling activity that favors more oil drilling relative to historic norms and a rapid jump in well complexity for US onshore wells.

Traditionally, most US onshore drilling activity has targeted natural gas, not crude oil.


Source: Bloomberg

This graph breaks down the total US rig count by targeted commodity. Five years ago, only 231 of the 1,478 rigs drilling in the US–roughly 15 percent of the total–sought crude oil. Of the 1,672 rigs active today, more than 40 percent are drilling for oil.

The reason for the shift is twofold. First, as most investors are well aware, natural gas is historically cheap relative to crude. Natural gas currently commands less than $4 per million British thermal units (BTU), while crude trades at roughly $14.50 per million BTUs on an energy-equivalent basis. The average spread was 1.5 to 1 from 1990 to 2005, so the current pricing environment is highly unusual.

Most US producers earn, at best, small returns on “dry” gas wells that are devoid of natural gas liquids (NGL) or condensate. At the same time, some operators can reap internal returns in excess of 100 percent from onshore oil wells. Regardless of a producer’s individual economics, there’s a wide differential between dry gas and liquids-rich plays.

Not surprisingly, independent producers of all sizes are limiting gas drilling–to the extent that they can without risking their leases–and shifting capital expenditures to oil production. For example, Chesapeake Energy Corp (NYSE: CHK), the second-largest US natural gas producer and most active driller, announced that it plans to quadruple its liquids output by 2015.

This uptick in onshore drilling couldn’t have occurred without advances in drilling techniques and technology that allow producers to extract crude trapped in shale and other tight bedrock. For additional details on Bakken Shale and other leading shale oil fields, check out the previous issue of The Energy Strategist.

The emergence of these plays has been a huge surprise. As recently as 2005, analysts widely assumed that the US onshore oil-directed rig count was in a long-term decline. In the late 1980s more than 600 rigs targeted onshore US oil plays, but this number shrank to 100 to 200 rigs from 1998 through 2005. At the time, existing US onshore oil fields were mature and on the down slope of their productivity, prompting operators to shift drilling activity to onshore natural gas plays or offshore fields.

But horizontal drilling and hydraulic fracturing unlocked the Bakken and other unconventional plays, touching off a boom in onshore oil-directed activity.

Concomitant with the rise of unconventional plays is an increase in well complexity. Whether they target oil or natural gas, modern wells are far more complicated than those drilled a decade ago. Horizontal wells are the norm in US shale plays, and producers have found that longer lateral segments produce superior results. Meanwhile, these fields also require fracturing to ensure that the trapped oil can flow through the reservoir rock and into the well.

The percentage of the US rigs drilling horizontal wells provides a quick indication of service complexity. Check out the graph below.


Source: Bloomberg

From the 1990s to 2004-05, less than 10 percent of US rigs were drilling horizontal wells. In just five years that ratio has more than quadrupled to 55 percent. And increasing well complexity spells more work for services firms.

Most analysts expected North American drilling activity to remain robust in the third quarter, but results surpassed expectations. In fact, before this earnings season, conventional wisdom held that depressed gas prices would lower the gas-directed rig count to such an extent that oil-directed activity wouldn’t be able to offset this shift. According to this scenario, North American activity would tail off into 2011.

Third-quarter results and comments from management suggest that an uptick in drilling for crude oil and NGLs should be enough to countervail any weakness in natural gas-focused activity. This transition is also good news for services outfits because the work surrounding an unconventional oil well is more intense than the development of an unconventional natural gas well.

I expect North American activity to remain a tailwind for the services industry. Even if the rig count falls slightly, the increased complexity of unconventional oil wells should enable services firms to grow earnings. Companies are already raising prices on key services, and that momentum should continue into next year.

Finally, note that although my comments have focused on the US, the Canadian market is enjoying similar trends. I’ve chosen to highlight the US rig count simply because drilling activity north of the border is subject to seasonal differences that sometimes obscure underlying trends. Suffice it to say that Canadian producers are also shifting their focus to oily plays.

Lumpy Growth Abroad

The international rig count–the number of rigs actively drilling for oil or gas outside the US and Canada–recently soared to 1,120, just above its 2008 pre-crisis highs of 1,108.


Source: Bloomberg

The last time the international rig count approached these heights was in 1986, just before drilling activity tumbled in the wake of the 1970s oil boom. As a rule, international drilling activity tends to be linked to oil prices and projects spearheaded by large integrated oil firms and national oil companies.

That being said, the recovery in international drilling activity and capital spending has been lumpy thus far. Whereas the UK, Brazil, Russia and China have been pockets of strength, Algeria, Mexico and other markets have been much slower to improve.

At a recent industry conference, Halliburton included a slide breaking down global rig count’s upturn since it bottomed in August 2009. Although the overall rig count has picked up, five countries–Argentina, India, Colombia, Egypt and Venezuela–have accounted for 75 percent of the increase.

Most of the services firms also noted that macroeconomic uncertainties had made international customers more cautious–an understandable reaction after commodity prices plummeted in late 2008 and early 2009. Management teams expect international conditions to improve in 2011, when a number of large projects ramp up. And the longer oil prices remain elevated, the more producers’ confidence levels should rise.

Meanwhile, a higher international rig count and broadening recovery in drilling activity should help pricing. Right now, the multinational services firms have excess capacity in many regions, making it tough to raise prices. As that situation reverses, profit margins will improve.

Gulf of Mexico Will Take Time to Heal

I’ve written about the Gulf of Mexico on numerous occasions since the Macondo spill. Here’s a quick refresher: Drilling activity in the region remains weak and won’t improve significantly in the near term.

Most of the major oil-services firms quantified the spill’s impact on their earnings prospects months ago, so third-quarter results didn’t yield any big surprises on that score. Still, it’s worth reiterating that just because the government lifted the drilling moratorium does not mean business has returned to normal in the Gulf.

No new wells are likely until new regulations are finalized, and producers will likely take their time to adjust to the new rules.

Bottom line: Don’t expect drilling activity in the Gulf to recover until at least a year.

Drilling Down

Now that we’ve addressed these bigger-picture trends, let’s delve into the third-quarter results and conference calls from three of the four biggest services firms.

Halliburton

Key Takeaways:

  • North American operations stole the show, benefiting from robust drilling activity and pricing gains for work in oil- and NGL-rich areas.
  • Increased well complexity onshore North America is driving margins higher and increasing revenue per well.
  • Strength in the North American market appears sustainable.
  • International operations are uneven, though the company was able to push through price increases in some markets.
  • The US Gulf Of Mexico will remain weak, but some of this activity has shifted to other deepwater markets. Capital spending on international deepwater projects has been strong despite the Macondo spill.

Halliburton (NYSE: HAL) reported solid third-quarter earnings that beat analysts’ expectations. Although the stock’s initial reaction to the news was negative, this weakness reflects profit-taking after a substantial run.

The company derives as much as 40 percent of its revenue from North America and is the leader in pressure-pumping capacity–a service that’s integral to hydraulic fracturing. Hands down, the company’s quarterly earnings and conference calls are essential for insight into the US and Canadian oil and gas markets.

Citing increasing well complexity and higher activity in oily plays, management noted that the US onshore rig count should remain elevated. The management team also expects that greater demand in 2011 will enable the firm to further raise the prices it charges for fracturing and other service, perhaps to levels last seen in mid-2008.

In addition to pricing gains, the company earns more revenue from each well drilled. Although the US onshore rig count is less than it was at its 2008 peak (1,672 rigs today, as opposed to more than 2,030 rigs then), Halliburton doesn’t necessarily have less work to do. Remember, more complex wells mean more work for services firm.

Consider these statistics. Management estimates that activity in oil- and NGL-rich plays accounts for more than 60 percent of the US onshore rig count–a much higher proportion than anyone expected two years ago. This shift should be sufficient to offset any decline in activity targeting dry gas.

It will also reduce the volatility of the US onshore oil services and drilling markets. Natural gas prices are notoriously volatile, prompting some futures traders to dub the commodity the widow-maker. A shift away from gas-directed drilling should steady demand. That’s not to suggest that oil markets don’t experience unnerving gyrations. However, because oil prices depend on international supply and demand conditions rather than the health of the US economy, this commodity doesn’t experience the gut-wrenching volatility associated with natural gas.

More important, Halliburton reports that average horsepower for pressure pumping in a North American well–a proxy for the amount of fracturing work– has increased by 50 percent. In addition, the length of time pressure-pumping equipment is used on each well has more than doubled from peak levels in 2008.

For example, two years ago most producers in the Bakken drilled 2,000-foot laterals and fractured these wells in eight stages. Today, the industry standard–not the state of the art–calls for 6,000-foot horizontal wells and more than 30 fracturing stages. In addition, wells in the oil-focused Bakken are 20 percent more service intensive than wells drilled in the Eagle Ford Shale’s NGL-rich window.

The demands of drilling these complex wells mean that equipment wears out even more rapidly. According to management, 10 percent of its fracturing capacity is undergoing maintenance at any given time–twice the percentage of two years ago. And Halliburton estimates that its downtime is among the lowest in the industry. Even though rivals are adding significant pressure-pumping capacity, many of these new-builds are destined to replace worn-out equipment.

Finally, Halliburton pointed out that it’s a mistake to assume that all of this increase in oil-related drilling activity and the parallel uptrend in well complexity have been driven by unconventional shale gas plays. In the Permian Basin–a mature, conventional oil-producing region located mainly in Texas–16 percent of the rig count is now drilling horizontal wells.

Producers, including Wildcatters recommendation Linn Energy LLC (NSDQ: LINE), are finding that horizontal wells yield better production rates in this mature parts of this region.

It’s not hard to see how these trends add up to more work and rising pricing power for the likes of Halliburton. Even if the rig count holds steady, Halliburton sees “more juice” in the pricing game.

Halliburton also discussed its efforts to develop a production model for dry-gas plays that lowers costs to the point that drilling is still economic at depressed gas prices. This initiative would lower margins in the near term but enable the firm to build market share before the eventual upturn. In addition to optimizing the drilling process, Halliburton will also bundle its services, limit price increases for gas producers and commit rigs to drilling in these regions rather than oilier plays.

Management’s comments suggest that this program is limited to a few large customers; I don’t foresee much of an impact on company-level margins.

It’s also interesting that producers are focusing so much attention on gas production cost reduction. Lower marginal production costs will hand producers significant earnings leverage when gas prices do recover–I expect gas prices to improve somewhat in the latter part of 2011.

You can’t talk about North American drilling without discussing the Gulf of Mexico.

As investors undoubtedly recall, Halliburton was one of the services companies involved in BP’s (NYSE: BP) infamous Macondo well. I wrote about the spill at some length in the May 5 issue, Opportunity amid Crisis, which included a discussion of Halliburton’s role in the debacle. As I noted then, the odds that Halliburton will bear any liability from the spill are remote.

The stock sold off last week after reports suggested that the cement mixture Halliburton used on the Macondo wasn’t appropriate. Standard & Poor’s also lowered the oil-services firm’s credit rating to reflect heightened legal risk. Both the market’s reaction and S&P’s downgrade are fundamentally off-base; the contract governing Halliburton’s work on the well makes it nearly impossible for them to have legal liability.

The fallout from the drilling ban in the Gulf also showed up in Halliburton’s third-quarter results, though the hit was less than management had forecast–primarily because the firm earned significant revenue drilling the two relief wells that finally sealed the Macondo. But this one-off work won’t bolster results in the fourth quarter; like the other major services firms, Halliburton expects activity in the Gulf to remain restrained for some time.

Results from the firm’s international operations were less sanguine; management described this side of the business as “treading water.” That being said, Halliburton has been able to raise prices in markets where activity has ramped up substantially and capacity for key equipment and services is tight. Of course, these gains are offset by weak growth and competitive pricing in other markets.

Three specific comments related to international markets stood out during the third-quarter conference call.

First, management noted that although roughly three-quarters of all spending on deepwater projects focuses on the Golden Triangle–Brazil, West Africa and the Gulf of Mexico–opportunities have emerged in the Mediterranean and other regions. These new deepwater markets, coupled with strong demand offshore Brazil and West Africa, suggest that the Gulf oil spill and drilling moratorium won’t change long-term growth dynamics.

Some talking heads cost investors a great deal of money back in May and June by predicting the end of deepwater drilling as we know it. That’s not happening: Deepwater remains one of the most exciting growth areas for hydrocarbon production.

Encouraging news related to deepwater contrasts dramatically to the situation in Mexico, a country that’s at risk of becoming a net oil importer after being one of the top exporters to the US. CEO David Lessar’s comments on the Mexican market were instructive:

…if you go back 12 months ago, there were relatively bullish comments made by PEMEX [Mexico’s national oil company] at that time. And I don’t say that in a disrespectful way to PEMEX. It’s just I think it’s in their interest to keep as much of the service company interest engaged in Mexico for as long as possible. However, we have a business to run, not only in Mexico but in the rest of North America. And there is a lot of demand for the equipment we have tied up in Mexico. Or had tied up in Mexico.

So, it’s still a market that we like for the long term. We have won a significant amount of discrete services bidding that’s gone on down there in the past several months. But as far as these integrated projects go, I think the on-again off-again nature of them really doesn’t lead to an environment where you can make consistent profits. So that is certainly something that we are going to re-evaluate if those opportunities come back up, and we’ll have to decide whether we want to participate in them or whether there are better opportunities either for discrete services in Mexico or to pull that equipment–or additional amount of equipment out of there and redeploy it to other parts of the world.

You can sense Lessar’s frustration in the text and hear it in his voice if you replay the webcast of the conference call.

The big problem is that Mexico’s constitution effectively prevents PEMEX from partnering with foreign oil companies to develop its fields. In many countries the model has been for the national oil company (NOC) to partner with a deep-pocketed integrated oil company (IOC) that will help to develop a particular field in exchange for a stake in the production. This approach wasn’t an option in Mexico.

Enter the integrated project management (IPM) deal. Under an IPM deal, the NOC pays a fee to a services company such as Schlumberger, Halliburton or Weatherford International to manage the development of a particular field or group of fields. Under an IPM deal, the NOC doesn’t give up ownership of the reserve or a title to part of the production. For these reasons, IPMs have become an increasingly important force in recent years.

Mexico was one country that embraced the IPM concept as a way to develop its reserves, particularly the massive onshore Chicontepec play. As Mexico awarded contracts to develop Chicontepec and other fields, the big services firms ramped up their operations in the country. Unfortunately, Mexican politics intervened. When these IPM deals didn’t instantly provide a massive boost to production, lawmakers did an about-face and wound down activity in Chicontepec.

With excess equipment in Mexico and no prospects for new contracts, the services companies were left holding the proverbial bag.

In the wake of that disaster, it doesn’t appear that Halliburton and the other services firms are particularly keen to re-enter Mexico. Under these circumstances, it’s unlikely that Mexico will be able to maintain, let alone increase, its oil output.

Management also touched on an intriguing long-term opportunity, noting that activity and interest in international unconventional oil and gas plays have heated up. Although Halliburton didn’t get into specifics, the management team observed that capacity in pressure pumping and other service lines is insufficient to support international development. This could provide a longer-term opportunity for Halliburton and others to export technologies developed and perfected in North American shale plays to similar formations abroad.

Although Halliburton doesn’t appear in the model Portfolios, I am raising it to a buy in my Energy Watch List.

Schlumberger

Key Takeaways:

  • North American margins have improved rapidly because of pricing gains and cost-cutting.
  • International growth disappointed, as weakness in Mexico and start-up costs in Iraq offset strength elsewhere.
  • The international cycle is set to turn in 2011. Several deepwater projects will get underway, Schlumberger will introduce new technologies and start-up costs will abate.
  • Fundamentals for the WesternGeco seismic division are improving, and there’s no looming threat of global overcapacity.

Shares of Schlumberger (NYSE: SLB) rallied after management reportedthird-quarter earnings that were well above expectations and made positive comments about future growth.

Whereas Halliburton’s quarterly earnings and conference calls always provide useful insight into the North American market, Schlumberger, which derives only 15 to 20 percent of its revenue from this region, usually offers in-depth commentary on international markets.

In addition, because Schlumberger’s business mix favors drilling and exploration rather than well completion and development, management’s comments often serve as a good gauge of producers’ interest in exploring for new oilfields.

Schlumberger’s comments about North America broadly resembled those made by Halliburton, so I won’t belabor the point. However, it’s worth noting that management was noticeably more optimistic about the sustainability of North American growth and margins than in prior calls.

In Schlumberger’s second-quarter conference call, CEO Andrew Gould had that the North American market would remain solid through year-end but worried about the long-term impact of weak gas prices. In the third-quarter call, he amended his outlook slightly, calling for strength through at least the second quarter of 2011. The company enjoyed some of the strongest growth in North American of any services firm, thanks to cost-cutting and restructuring efforts.

The management team also spent a considerable amount of time discussing the lumpiness of international activity and profit margins. One analyst asked CEO Andrew Gould for a roadmap for international markets in 2011. Gould offered the following reply:

I think it’s important to analyze a little bit why margins have not improved significantly this year. And I think the first thing that you can say is that Mexico has dampened margins for Latin America, but virtually everywhere else in Latin America, margins have progressed.

You look at Europe/CIS/Africa (ECA). The North Sea had healthy improvements. West and Southern Africa, a lot of projects were delayed by Macondo but they started towards the end of the third quarter, so that will improve. The Gulf of Guinea, by which I mean everything from Ghana through Nigeria down to Equatorial Guinea, is being dampened by Nigeria and then, of course, North Africa has not been good. And so the slight decrease in margins in ECA is really due to the weakness in North Africa and the Gulf of Guinea which was too much to offset the improvement in the North Sea, Russia and West and Southern Africa. It’s sort of clear.

If you look at MEA [Middle East and Asia], the only reason our margin declined is because we took all the mobilization costs for the BP Rumaila project in Q3. If we had not had that cost, the margins would have been flat with Q2. So I–if you go forward into next year, I think that the deepwater activity improvement next year, because of the rigs coming on and because of the Macondo – there will hopefully not be a second Macondo effect, deepwater will improve more than it did this year. We are already seeing, to some extent, a renewal of exploration programs in areas other than the traditional areas in Africa. And that is helping.

And in the Middle East, if you leave aside Iraq, there are a number of other projects that have very healthy margins going forward. So overall, we’ve got delayed this year by some extraneous events and some activities that didn’t happen, but if oil prices stay where they are, I don’t see why margins shouldn’t progress next year.

Gould sums up the international situation quite well in this lengthy excerpt.

Just because overall margins were soft doesn’t mean that international markets aren’t recovering; rather, the weakness stemmed from sluggish activity in a few key markets, many of which suffered because of political issues rather than a lack of attractive prospects.  

In the Middle East, Iraq is the biggest obstacle to higher margins, though the four biggest services firms are all ramping up their operations in the country to support several major production deals the government awarded in 2009.

In Schlumberger’s case, the company took a large charge related to the start-up of BP’s Rumaila contract; these start-up costs depress profits in the short term but will be recouped when the projects start to generate revenue in 2011.

Over the long term, Iraq is a potentially huge opportunity for all of the services firms. Investors looking to participate in Iraq’s oil production growth should focus on the services companies, not the big integrated producers that won contracts in the nation.

The winning producers signed contracts with fairly tough terms–they only receive a small margin on oil produced and must meet aggressive output targets. But to even make an effort to meet those targets, they’ll need to drill aggressively and perform maintenance work on older wells. Some analysts estimate that Iraq could be worth as much as $7 to $10 billion annually to the services firms once activity ramps up.

One caveat is crucial: Don’t believe sensationalistic articles which claim that Iraq’s oil fields will soon flood the world with oil. The contracts Iraq signed with major oil companies in 2009 set a production goal of 12 million barrels of oil per day, up from current output of roughly 2.5 million barrels per day. Some have reported this goal as though it were a done deal. The reality is that all of the oil companies, and the Iraqi government itself, know that a target of 12 million barrels per day is downright silly.

The Iraqi Ministry of Planning recently revised its 2014 oil production target to 4.5 million barrels per day. Most private estimates suggest oil output won’t reach the 4.5 million barrels until 2015. The CEO of Total (NYSE: TOT) indicated that he felt that oil production of 7 to 8 million barrels per day “eventually” would be considered a tremendous success.

In short, producers will spend a great deal on services in Iraq and production will increase, but don’t believe the hype about a massive jump in production.

The good news is that Schlumberger’s comments suggest 2011 will bring an inflection point for international margins. With Iraqi start-up costs fading and deepwater markets (outside the US Gulf of Mexico) already picking up after a temporary post-Macondo lull, pricing power in international markets will begin to climb. And because most of the services companies have scaled back operations in Mexico after the country’s bait-and-switch move, the market should be less of a drag going forward.

One area that showed surprising strength was WesternGeco, Schlumberger’s seismic division. This business uses sound and pressure waves to map underground rock formations and identify area that are prospective for oil or gas. Although producers also use seismic data to help them develop known fields, it’s typically regarded as a service function levered to exploration spending.  

Analysts had been concerned about Schlumberger’s seismic business in the wake of the Macondo oil spill. For one, the Gulf of Mexico was a big market for this service until the moratorium halted new drilling. In addition, ships that acquire seismic data left the Gulf and flooded into international markets creating a glut of supply and pinching margins. And finally, a number of new advanced seismic ships have been built or will soon be completed, increasing the supply even more.

Surprisingly, Schlumberger noted an uptick in interest from larger operators in acquiring seismic data in the Gulf. Despite the moratorium, the largest producers appear to be acquiring data ahead of planned lease sales next year. This is a reminder that although the Gulf has been weakened by the moratorium, it’s not going to be out of commission forever.

Schlumberger also stated that it’s seeing a pick-up in demand for advanced, high-definition seismic data shoots outside the US Gulf. In particular, the company has done big seismic shoots in the North Sea, West Africa, the Red Sea and Brazil. In the fourth quarter, the oil services giant has a contract to undertake another shoot in the Mediterranean. This commentary jibes with Halliburton’s comments surrounding new deepwater exploration beyond the Golden Triangle.

And Schlumberger indicated that demand from these regions is enough to absorb excess ships from the Gulf and the new-build seismic fleet. Next year won’t bring a glut of seismic capacity. Schlumberger’s management is usually conservative when making comments of this nature; I regard this as a good sign.

Schlumberger will also get a margin boost from new technologies in 2011. In the company’s prepared remarks, management discussed three new technologies it’s introducing and testing: a new technology to evaluate the oil or gas content of a reservoir; a new technology that reduces the cost and drill times of horizontal wells; and a set of new oil production-related software products. New technologies tend to earn higher profit margins, so these introductions are encouraging.

Finally, the acquisition of Smith International has been a major focus for management in recent months. But the integration appears to be going well. Some complained that Schlumberger overpaid for Smith, but it’s hard to argue against the strategic rationale.

Schlumberger is gearing up for a major acceleration in growth into 2011. When international growth picks up and profit margins begin to improve, the oil-services group tends to enjoy a multiyear period of outperformance.  Schlumberger ran up from a split-adjusted $30 per share in late 2004 to well north of $100 in 2007.

Schlumberger continues to rate a buy under 85 in the growth-oriented Wildcatters Portfolio.

Weatherford International

Key takeaways:

  • Leveraged to continued strength in the North American market.
  • New international projects slated to start up in 2011 bode well for earnings growth.
  • The Mexican debacle is mostly in the rearview.
  • Expertise in producing mature wells should remain in demand.

Weatherford International’s (NYSE: WFT) general comments about North American and international markets echoed those of Halliburton and Schlumberger. 

Management compared 2010 to 2004 and the 2011-13 to 2005-07. In other words, 2004-05 was the point in the last cycle where international markets started to heat up. This led to a period of extraordinarily strong margins and growth in 2006-07. If that characterization is even half correct, it’s bullish for shares of Weatherford International; the stock nearly quadrupled between late 2004 and mid-2008. 

A few company-specific developments are worth highlighting.

CEO Bernard Duroc-Danner described the Mexican market as a “crushing ulcer” for Weatherford, echoing the sentiment of the other services firms, albeit in more colorful language.

Weatherford was particularly badly burned because the contracts represented a bigger proportion of its business than it did for Schlumberger. The market utterly collapsed when the government suddenly decided to shut down all activity in about half the fields in Mexico. Weatherford had 47 to 50 strings (basically wells) running at the end of 2009 but had only three as of the end of the third quarter.

That being said, Weatherford noted that things can’t get any worse in Mexico, and firm has already scaled down its operations and moved equipment out of the market.

Weatherford is also big in Russia, thanks to its acquisition of the oil services unit of TNK BP. The Russian market is doing well; Weatherford’s outsized presence shouldbe a benefit heading into 2011.

And the company has exposure to Iraq. The company has pumped considerable investment into building up its infrastructure there, so start-up costs related to new projects are high. But Weatherford does appear to be in a good position to benefit from the services ramp-up in that country.

Finally, it’s worth noting that artificial lift accounts for a third of Weatherford’s revenue. These inections enable producers to pump more oil out of mature oilfields. The key here is that artificial lift is totally oil focused and has zero gas exposure; in contrast, fracturing and horizontal drilling are services used in gas and oil wells. Weatherford’s heavy oil-specific focus is a competitive advantage in North America as is its traditional strength in Canada, where spending on heavy oil and oil sands projects is likely to ramp up over the next few years.

Weatherford International rates a buy under 26 in the Wildcatters Portfolio.

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 15 Fresh Money Buys that includes 13 names 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. Here’s the list, followed by a short update on picks with major news events.


Source: The Energy Strategist

Comments and Updates

Super major Chevron (NYSE: CVX) sold off after reporting results that were roughly in line with estimates. Having handily outperforming its peers in 2010, the stock was due for some profit-taking. Our investment thesis remains intact: Chevron has the best long-term production growth outlook of the majors. Take advantage of this slight dip to buy Chevron.

Enterprise Products Partners LP (NYSE: EPD) reported yet another blow-out three months and raised its payout for 25th consecutive quarter.  The master limited partnership (MLP) covered its distribution 1.4 times, a high ratio for an MLP, and I particularly like its strong position in the Eagle Ford Shale.

Penn Virginia Resource Partners LP (NYSE: PVR) has continued to perform and recently raised its distribution once again. Given the stock’s run, I’m reviewing the company’s fundamentals to determine whether a higher buy target is justified. For now, only buy Penn Virginia Resource Partners LP in dips under 26.

Shares of EOG Resources (NYSE: EOG) sold off after management’s production guidance disappointed expectations. Some of the shortfall stemmed from the tight supply of fracturing equipment, while EOG has also continued to reduce its gas output. Investors overreacted to the news; EOG still boasts some of the best oil production growth potential in my coverage universe. Take advantage of the dip and buy EOG Resources up to 115.

A driller with exposure to international deepwater projects and impressive contract coverage, Seadrill (NYSE: SDRL) is insulated from ongoing issues in the Gulf of Mexico. I’m boosting my buy target on Seadrill to 33.

Uranium prices have soared to $52, as utilities, investors and producers all entered the spot market to secure supplies. As I predicted in the Oct. 6 issue, this market is tightening and uranium stocks are on the move. Cameco Corp (TSX: CCO, NYSE: CCJ) is a buy in my Nuclear Power Field Bet.

Peabody Energy Corp (NYSE: BTU) reported stellar earnings, thanks to accelerating coal demand in Asia. The US coal market remains weak, but Peabody’s domestic production is almost fully contracted for 2011. I’m raising Peabody Energy Corp to a buy under 55.

Suncor Energy (TSX: SU, NYSE: SU) has strong production growth potential in the Canadian oil sands, and crude is trading well north of $80a barrel. What’s not to like? Buy Suncor Energy under USD43.

Cameron International’s (NYSE: CAM) third-quarter earnings were in line with expectations, but management expects margins to trough over the next three months. Rising margins will be a key catalyst for the stock. With its advanced blowout preventers likely to become required equipment on deepwater rigs, Cameron International is a buy up to 46.

Afren (LSE: AFR) is an oil-focused explorer that’s benefiting as majors exit smaller African. Buy Afren under 135 pence on the London exchange.

Nabors Industries (NYSE: NBR) posted stellar third-quarter earnings and should continue to benefit from increasing activity in US unconventional plays. Stepped-up drilling activity in Iraq could also provide upside for the stock. Buy Nabors Industries up to 28.

I like Knightsbridge Tankers’ (NSDQ: VLCCF) mixture of spot and long-term contracts and its high yield potential. I’m raising my buy target on Knightsbridge Tankers to 25.

First Solar (NSDQ: FSLR) continues to underperform relative to traditional energy plays, and the firm’s profit margins declined for the fifth consecutive quarter. Declining subsidies for solar power will have more of an impact than management lets on. Sell First Solar short above 110.

Shares of Diamond Offshore (NYSE: DO) have been dragged higher with the rest of the sector but has lagged its peers significantly Excessive exposure to the US Gulf of Mexico and a fleet of aging rigs are big negatives. Sell Diamond Offshore short above 60.

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