Shares of Growth Portfolio holding Weatherford International (NYSE: WFT) have tumbled more than 12 percent today, largely because the company has yet to resolve the tax accounting issues that management first disclosed a year ago. Last year’s revisions were all noncash restatements, and we expect the latest adjustments will also be noncash. This news has overshadowed the oil-field service outfit’s solid fourth-quarter results and encouraging operational trends.

Although this lingering accounting issue is frustrating, Weatherford International and its peers should continue to benefit from recovering margins in international markets and an upsurge in offshore exploration and development. A slew of recent discoveries in the Kwanza Basin off the coast of Angola and other deepwater fields have led to a faster-than-expected recovery in this market segment. At the same time, deepwater activity in the Gulf of Mexico also continues to pick up.

With profit margins likely to remain relatively flat in North American shale plays, investors should favor Schlumberger (NYSE: SLB) and Weatherford International, both of which have more exposure to international growth stories than Baker Hughes (NYSE: BHI) and Halliburton (NYSE: HAL).

Weatherford International has less exposure to natural gas-focused services in North America than any of its peers and has strong leverage to international markets and oil-related services. For these reasons, the stock has rallied more than 55 percent from its October low to last Friday’s close. That’s compared to the 36 percent gain posted by shares of Schlumberger, the 27 percent return posted by Halliburton and the 13.3 percent gain posted Baker Hughes. Even after today’s correction, Weatherford International’s stock will likely have outperformed shares of the other major services firms since that October low.

The investment case for Weatherford International continues to rest on its leading market position in rapidly growing markets such as artificial lift, a service line that enhances production from mature oil fields. I will analyze the company’s results and subsequent conference call in this week’s issue of The Energy Strategist.

Although the company’s failure to resolve this accounting charge is disappointing, today’s announcement is unlikely to undercut the case for investing in Weatherford International.

The company expects restatements of $225 million to $250 million related to 2010 fiscal year and prior–for comparison, the company’s gross profits on a trailing 12-month basis are more than $2.6 billion on more than $12 billion in revenue. Although additional inconsistencies could emerge and these numbers are hardly pocket change, these restatements won’t threaten the franchise.

The selloff in shares of Weatherford International appears overdone and is unlikely to stick. However, this latest misstep won’t help investors’ confidence in senior management; a shake-up could be in order at the top. Investors would likely cheer any leadership changes. At the same time, the company’s favorable positioning in the current operating environment and cheap valuation could make it a takeover target. Weatherford International rates a buy under 20. 

Editor’s Note: Elliott will host the next Energy Strategist Live Chat on Feb. 16, 2012, at 2:00 p.m. EST. This is your opportunity to ask questions about specific Portfolio recommendations or broader trends in the energy patch. Click here for more information or to sign up for an email reminder.

The three largest oil-field services firms–Baker Hughes (NYSE: BHI), Halliburton (NYSE: HAL) and Schlumberger (NYSE: SLB)–account for roughly 64 percent of the global market for pressure pumping, a service that’s critical to extracting oil and gas trapped in shale and other tight formations. The quarterly results and subsequent conference calls from these companies often serve as the Rosetta stone for oil and gas investors.

In a process known as “fracking,” exploration and production companies book pressure pumping capacity to pump large volumes of water mixed with sand and chemicals into the field, fracturing the low-permeability reservoir rock and enabling the hydrocarbons to flow into the well.

In recent years, frenzied drilling in unconventional oil and gas fields such as the Bakken Shale in North Dakota, the Eagle Ford Shale in Texas and the Marcellus Shale in Pennsylvania has allowed the US to boost its annual oil output for the first time in decades and overtake Russia as the world’s leading producer of natural gas.

Source: Energy Information Administration

Even more impressive, oil production has increased despite plummeting output from the US Gulf of Mexico.

Source: Energy Information Administration

This surge in drilling activity has significantly boosted the revenue and margins of Baker Hughes, Halliburton and Schlumberger. In 2011, global spending on pressure pumping soared to $31 billion, up 63 percent from 2010. However, the outlook for 2012 is less sanguine: As reported by Platts and Bloomberg, respected energy consultancy Spears & Associates estimates that the global market for pressure pumping in 2012 will grow by a considerably less robust 19 percent, to $37 billion.

Pricing Pressure on Pressure Pumping

With natural gas prices at depressed levels and unlikely to improve for at least two to three years, Chesapeake Energy Corp (NYSE: CHK) and a host of other operators have announced plans to scale back drilling once again in gas-rich basins such as the Haynesville Shale.

Producers already generated thin margins in these regions, limiting services firms’ ability to push through price increases. Wellhead economics in gas-focused plays will worsen in 2012. In the past, hedges had bolstered producers’ price realizations on natural gas. Today, futures prices are far less attractive, accelerating the industry’s exodus from gas-focused basins and into oil and natural gas liquids (NGL)-rich plays that offer superior wellhead economics.

A corresponding migration is occurring in the pressure-pumping market, with services firms shifting capacity to established plays such as the Bakken Shale and the Eagle Ford Shale, as well as the Utica Shale in Ohio and other emerging basins. The industry consensus calls for increased activity in liquids-rich basins to at least offset the slowdown in gas-producing fields.

Disregarding the near-term revenue hit from relocating service capacity, the big question centers on the extent to which the influx of hydraulic-fracturing equipment to liquids-rich fields will weigh on the oil services industry’s pricing power. The rising cost of sand, ceramic material, gels and other inputs likewise present a challenge to pressure-pumping margins.

During a conference call to discuss fourth-quarter results, Schlumberger CEO Paal Kibsgaard acknowledged these new realities and cautioned that developments in North America could weigh on margin growth in the pressure pumping segment:

[I]f you look at pressure pumping pricing levels, as I said, we continue to see downward pressure on pricing in gas in Q4. The liquid basins, we saw pricing basically being flat, some contracts being up and some contracts being down. Now, how this is going to go to hold, I think, is still uncertain at this stage, right? There is obviously a chance that the continued [in]flux of capacity from the gas basins into the liquid basins is going to have an impact on liquids pricing as well. We haven’t really seen any downwards trend yet, but clearly, over the past quarter, the pricing has been flat. So that’s basically where we stand on that.

Halliburton CEO David Lesar sounded incrementally more bullish during a conference call on Jan. 23, 2012:

As we look at the market dynamics today and even apply a down side scenario to how it might play out, based on frac [hydraulic-fracturing] equipment adds as well as reduced gas drilling, which would accelerate the equilibrium in the market for pumping, it is clear to us that the strength of liquids demand will provide a cushion to equipment coming out of the dry gas basins. We also believe that there will be a net overall increase in rig count in 2012, meaning that in our view, the increase in liquids-directed rigs will more than offset the decline in natural gas rigs.

Lesar asserts that the ongoing migration from dry-gas fields to liquids-rich plays should help preserve the existing supply-demand balance and prevent a collapse in pressure-pumping prices. However, the Halliburton chief also acknowledged that profit margins faced headwinds:

The problem, I think, that we face as we look forward is what will inflation do? As Dave commented, we’re going to have continued challenges with logistics, with the supply chain and moving proppants and gels and other things into those basins, because they’re in short supply, and we’re fighting back inflation as hard as we can.

Most of the price increases that I think that we’re being able to achieve right now are serving to basically offset that inflation. We’re going to have to work hard, as Dave commented, to really push back and see if we can get some relief from some of our suppliers as things soften in the gas basins. But we’ll have to continue to work to make sure that we can get all of that passed through with the price increases that we get.

So I think that as I said, it’s a little early to comment as to how much we can move pricing on a net basis north–I just can’t–I can’t speculate at this point whether we’ll be able to go back and get them back above those levels that we had in Q3 or even higher.

The International

Perhaps in response to concerns about pressure-pumping margins in North America, Halliburton and Schlumberger chose to highlight growth opportunity that’s emerging as exploration and production firms attempt to apply the American experience to international shale oil and gas fields.

At first blush, this trend offers plenty of potential upside to revenue and margins: Spears & Associates estimates that the North American market in 2011 accounted for 87 percent of the global market for pressure pumping, while a study sponsored by the US Energy Information Administration (EIA) estimated the technically recoverable shale gas resources in 32 countries at 5,760 trillion cubic feet. The table below lists the 10 countries with the highest amount of recoverable shale gas volumes. Note that the report excludes Russia.

Source: Energy Information Administration

During Schlumberger’s conference call to discuss fourth-quarter results, Kibsgaard noted that demand for pressure-pumping capacity has increased in international markets at a much faster rate than management had anticipated. Much of this pilot and early-stage work involves reservoir characterization and drilling test wells to help operators formulate a plan for extracting these resources as efficiently as possible. Kibsgaard identified China and Argentina as two countries where activity would pick up.

Timothy Probert, Halliburton’s president of strategy and corporate development, on Jan. 23 told analysts that the firm had screened 150 unconventional plays worldwide, 60 of which it examined in detail. When asked to describe the growth opportunity in international markets, Probert referred to developments in Latin America:

In 2012 it sort of feels to us like there are somewhere between 75 and 100 wells which will be drilled for shale activities in Latin America, and I just–if we put that in perspective with respect to a Haynesville [a gas-rich shale play in Louisiana], for example, which is just sort of about 99 rigs or thereabout at the moment, and clearly if you divide that or multiply that 99 rigs by 3 or–let’s say 4 to 6 wells per year–we’re dealing with a significantly smaller opportunity today. But the opportunity is growing, and…we’re in the sort of primarily exploration appraisal phase, low horse power requirements, primarily vertical, now shifting to horizontal where horsepower requirements are doubling as well as an increase in activity. So we think 2012 is a pretty good transition year for unconventionals, and we’ll see the most significant uptick in ’13 and ’14.

In next week’s issue of The Energy Letter, we’ll examine unconventional resources in China and Argentina. Investors, take note: exploration and development of many international shale oil and gas fields likely represents a longer-term growth opportunity.

The US shale gas revolution was abetted by ample reservoir data and elevated natural gas prices–five yeas ago, the nation faced a shortage of the thermal fuel. But a lack of geological information and a challenging price environment, among other difficulties, means that these emerging plays are unlikely to enter commercial production within the next five years.

Around the Portfolios

Aggressive Portfolio holding Oasis Petroleum (NYSE: OAS), which will report its fourth-quarter earnings on Feb. 22, 2012, announced that the company more than doubled its production in 2012 to 10,724 barrels of oil equivalent per day (boepd) from 5,206 boepd. This output fell short of management’s prior guidance of between 11,000 and 12,500 boepd, a result that contributed to the stock’s recent downdraft. Management also estimated Oasis Petroleum’s 2012 production at 18,000 boepd to 22,000 boepd.

Oasis Petroleum and other operators in the region will face lower oil price realizations in the first quarter because of planned maintenance outages at a few Midwestern refineries. Nevertheless, the company remains our top pure play on rising oil production in the Bakken Shale and is a prime takeover target. Buy Oasis Petroleum up to 38.

Both of the US royalty trusts in the Growth Portfolio trade substantially above our buy targets.

SandRidge Mississippian Trust I (NYSE: SDT) has gained more than 60 percent since we added the stock to the Portfolio on Oct. 6, 2011. The current price of $36.50 per unit is well beyond our buy target of $30 per unit. Meanwhile, units of Chesapeake Granite Wash Trust (NYSE: CHKR) trade above our buy target of $25 and have returned almost 50 percent since we highlighted the stock on Nov. 23, 2011.

Although both oil and gas trusts remain attractive investments for income seekers, investors should hold off on buying either stock until the prices dip below our buy targets. Heed the old Wall Street saw that bulls make money, bears make money, and pigs get slaughtered; if you’re sitting on substantial gains in these recommendations, consider taking some profits off the table.

Rather than selling your entire position in either trust, sell one-third to half your units of SandRidge Mississippian Trust I and Chesapeake Granite Wash Trust. Such a move would harvest some of your profits while retaining exposure to any further upside.

Although the stock market has rallied since thus far in 2012, investors should expect a pullback at some point this year; such a correction would likely offer investors an opportunity to buy these trusts at prices below our buy targets.

Both trusts rallied substantially after announcing distributions well above their target levels for the fourth quarter.

SandRidge Mississippian Trust I announced a quarterly payout of $0.790905 per unit, roughly 26 percent more than the targeted distribution and comfortably above its incentive distribution level. Chesapeake Granite Wash announced a payout of $0.7277 per unit, about 7 percent above the target laid out in the prospectus. Investors unfamiliar with the concept of the target and incentive distribution levels should check out the Oct. 6, 2011, issue of The Energy Strategist, The Yield Issue.

These higher-than-projected distributions stem from higher oil prices relative to the forecasts in the trusts’ registration statements. SandRidge Mississippian Trust I also appears to be drilling the 123 developmental wells required under the terms of the trust agreement at a faster-than-expected pace: As of Nov. 30, 2011, the trust had already drilled 48.9 of its 123 wells. In other words, the sponsor has drilled almost 40 percent of the required wells.

I’m adding a third trust the Growth Portfolio: SandRidge Permian Trust (NYSE: PER) rates a buy under 26.This trust will also replace Chesapeake Granite Wash Trust in my Best Buys list. The Nov. 23, 2011, issue of The Energy Strategist, Royalty Trusts: Buys and Sells, analyzes this trust in detail.

SandRidge Permian Trust offers everything I look for in an oil and gas trust: The vast majority of the trust’s production is oil; the trust has significant near-term hedges against commodity prices; the trust has a subordinated-unit structure that protects unitholders’ distributions over the next few years; and the trust is scheduled to drill 888 low-risk, developmental wells that will keep distributions rising over the next few years. The parent, SandRidge Energy (NYSE: SD), also sponsors SandRidge Mississippian Trust I.

The trust will disburse $0.553523 per unit for the fourth quarter. This payout is about 12 percent above the trust’s target. I expect elevated oil prices to boost the trust’s distribution in coming quarters. Based on current prices and my forecast for the trust’s next four quarterly distributions, the units should yield almost 11 percent. Buy SandRidge Permian Trust under 26.

Investors should also continue to buy Mid-Con Energy Partners LP (NSDQ: MCEP), a master limited partnership (MLP) profiled in the most recent issue of The Energy Strategist. This MLP offers similar tax advantages and income potential. Buy Mid-Con Energy Partners LP under 24.

The charter rates for both tankers and dry-bulk ships have weakened in recent quarters because of a persistent oversupply. The problem isn’t a lack of demand; rather, shipping firms ordered too many new ships during the 2004-07 boom years, and a glut of new ships is now entering the market.

Knightsbridge Tankers is insulated from the risk of near-term weakness in rates by its long-term charter contracts. These lease agreements signed should enable the ship owner to maintain its $0.50 quarterly dividend through at least the end of 2013. That’s equivalent to a yield of about 13.4 percent at current prices.

But the stock will tread water at best until sentiment toward the tanker industry improves. For that to happen, ship owners will need to scrap some of their fleet. We expect the tanker market to remain oversupplied until 2015. An investment in Knightsbridge Tankers will be dead money until that happens.

Read more…

5. Investors should also cover their short position in Diamond Offshore Drilling (NYSE: DO) for a loss of 6.3 percent. The company’s fleet of older rigs is disadvantaged in the current environment, leaving the stock with little room for upside. But the stock could enjoy a bump if day rates on deepwater drilling rigs ticks up. Investors should still avoid Diamond Offshore Drilling.

Read more…

Like most upstream MLPs, Mid-Con Energy Partners operates in established plays that feature limited drilling risk and predictable decline rates.

When the first well is drilled in an untapped field, pent-up geologic pressure forces the hydrocarbons into the well and to the surface of the earth, a process known as “primary” production. This reservoir pressure declines throughout the well’s life span, reducing the rate of production. More than 90 percent of Mid-Con Energy Partners’ wells have been in production since 1982 or earlier.

These mature wells still have value and can yield oil and gas for decades after their output peaks: Less than 20 percent to 30 percent of recoverable reserves are extracted during primary production.

Although mature wells won’t generate much production growth, these assets fit well within the MLP structure because of their predictable decline rates and low maintenance costs.

Mid-Con Energy Partners uses water flooding to enhance production from their wells. This secondary-production technique involves injecting water into the periphery of a field to restore reservoir pressure and push oil toward producing wells.

More than 90 percent of the MLP’s 272 producing wells employ water flooding to improve production rates. Six to 18 months of water injections are required to increase production, but the technique works: At the end of the third quarter of 2011, Mid-Con Energy Partners’ acreage yielded about 1,343 barrels of oil equivalent per day–up 100 percent on a year-over-year basis. Management attributes about 75 percent of this production growth to water flooding; acquisitions and basic maintenance work accounted for the remainder of these gains.

Mid-Con Energy Partners has two options for growing cash flow: ramping up production in its existing leasehold and making bolt-on acquisitions.

Operating in mature fields doesn’t constrain Mid-Con Energy Partners’ prospects for organic growth. Consider the MLP’s ongoing operations in the Highlands Field, an area that’s been in production since 1980 and has already yielded more than 3 million barrels of oil. The outfit began water flooding this play in October 2008, and production rates began to tick up in April 2009. Today, the field produces about 657 barrels of oil equivalent per day, up more than sevenfold from just 91 barrels of oil equivalent per day in January 2010.

At this point, Mid-Con Energy Partners has pumped enough water into the field to offset about 27 percent of the liquids extracted from the play since 1980. Output from this enhanced-recovery technique will peak once the MLP has injected an equivalent amount of water to previous production. Management estimates that the field’s gross output will exceed 1,500 barrels of oil equivalent per day once this occurs.

These water-flooding projects can extend a field’s productive life by more than a decade. Mid-Con Energy Partners began pumping water into the Southeast Hewitt Unit in June 1997, 18 years after the field was first discovered. Output from the field began to tick up in November 1997. Management estimates that the volume of water pumped into the field represents about 98 percent of extracted resources. Production from the field peaked in 2010–about 13 years after secondary production began.

Mid-Con Energy Partners also has ample opportunity to grow its output and cash flow through acquisitions. The MLP has formed two limited liability companies (LLC) with Yorktown Partners, a private-equity firm that focuses on energy-related assets and owns Mid-Con Energy Partners’ general partner. These LLCs will acquire properties where producers are already using water-flooding to enhance output and acreage that appears well-suited for this approach.

Mid-Con Energy Partners’ management team initiated almost one-quarter of all water-flooding projects in Oklahoma over the past six years, which inspires confidence in the firm’s ability to identify lucrative bolt-on acquisitions. In addition, Yorktown Partners, which has about $3 billion in assets under management, has already invested in a number of oil- and gas-producing properties that might be a good fit for Mid-Con Energy Partners.

By dropping down a new water-flooding project to Mid-Con Energy Partners, Yorktown Partners would be able to immediately monetize this asset and shield ongoing revenue from the field from corporate taxation. Meanwhile, rising production and cash flow from the dropped-down asset would enable Mid-Con Energy Partners to grow its distribution. With an almost 50 percent stake in Mid-Con Energy Partners’ outstanding units, Yorktown Partners has ample incentive to pursue strategies that will foster the MLP’s growth.

Hedges help to insulate the partnership from fluctuations in commodity prices. Management aims to hedge between 50 and 80 percent of total production over a rolling three- to five-year period. At present, the MLP has hedged about 53 percent of its 2012 production and 30 percent of 2013 production, locking in prices of about $100 per barrel.  

Although Mid-Con Energy Partners’ hedge book isn’t as comprehensive as that of Growth Portfolio holding Linn Energy LLC (NSDQ: LINE), the MLP’s exposure to rising oil prices could bolster cash flow.

Mid-Con Energy Partners plans to pay a minimum quarterly distribution of $0.475 per unit, equivalent to a 12-month yield of approximately 9 percent. The MLP pays its general partner 2 percent of any distributable cash flow.

Management estimates that the MLP will generate enough cash flow to cover its full-year 2012 minimum distributions by a healthy 1.2 times. However, this projection assumes that the partnership will grow it production by roughly 80 percent and that crude oil prices will average about $96 per barrel. Based on the firm’s production history, these estimates don’t appear overly aggressive, though cash flow could take a hit if oil prices tumble.

I’m making a number of changes to the names in my Best Buys list.

1. SandRidge Mississippian Trust I (NYSE: SDT) is a US energy trust that I first profiled and added to the Growth Portfolio in the Oct. 6, 2011, issue of The Energy Strategist, The Yield Issue. Since joing the model Portfolio, the trust has already delivered a total return of almlost 50 percent–an impressive gain. Strong oil and liquids pricing should enabled the trust to continue to pay a distribution that exceeds the target levels laid out in its prospectus. Based on the trust’s most recent quarterly dividend, the units currently yield 9.7 percent. I expect the trust to disburse between $3.50 and $4 per unit in 2012, equivalent to a yield of between 10.5 and 12 percent.

Investors sitting on a substantial gain from this position should consider taking some profits off the table and allocating the proceeds into the other high-yielding names in my Best Buy list.

Investors should also be on the lookout for the initial public offering of SandRidge Mississippian Trust II (NYSE: SDR) in early April. I analyzed this exciting prospect in the Jan. 25, 2011, issue of The Energy Strategist Weekly, Energy Investing: Eagerly Awaiting the IPO of SandRidge Mississippian Trust II.

3. I am also adding a new stock the Growth Portfolio and my Best Buys list: Mid-Con Energy Partners LP (NSDQ: MCEP). This upstream master limited partnership (MLP) owns about 9.9 million barrels of oil-equivalent reserves in Oklahoma, Kansas and Colorado. Crude oil accounts for 98 percent of these estimated reserves, a favorable asset base at a time when natural gas prices continue to hover near record lows.

Like most upstream MLPs, Mid-Con Energy Partners operates in established plays that feature limited drilling risk and predictable decline rates.

When the first well is drilled in an untapped field, pent-up geologic pressure forces the hydrocarbons into the well and to the surface of the earth, a process known as “primary” production. This reservoir pressure declines throughout the well’s life span, reducing the rate of production. More than 90 percent of Mid-Con Energy Partners’ wells have been in production since 1982 or earlier.

These mature wells still have value and can yield oil and gas for decades after their output peaks: Less than 20 percent to 30 percent of recoverable reserves are extracted during primary production.

Although mature wells won’t generate much production growth, these assets fit well within the MLP structure because of their predictable decline rates and low maintenance costs.

Mid-Con Energy Partners uses water flooding to enhance production from their wells. This secondary-production technique involves injecting water into the periphery of a field to restore reservoir pressure and push oil toward producing wells.

More than 90 percent of the MLP’s 272 producing wells employ water flooding to improve production rates. Six to 18 months of water injections are required to increase production, but the technique works: At the end of the third quarter of 2011, Mid-Con Energy Partners’ acreage yielded about 1,343 barrels of oil equivalent per day–up 100 percent on a year-over-year basis. Management attributes about 75 percent of this production growth to water flooding; acquisitions and basic maintenance work accounted for the remainder of these gains.

Mid-Con Energy Partners has two options for growing cash flow: ramping up production in its existing leasehold and making bolt-on acquisitions.

Operating in mature fields doesn’t constrain Mid-Con Energy Partners’ prospects for organic growth. Consider the MLP’s ongoing operations in the Highlands Field, an area that’s been in production since 1980 and has already yielded more than 3 million barrels of oil. The outfit began water flooding this play in October 2008, and production rates began to tick up in April 2009. Today, the field produces about 657 barrels of oil equivalent per day, up more than sevenfold from just 91 barrels of oil equivalent per day in January 2010.

At this point, Mid-Con Energy Partners has pumped enough water into the field to offset about 27 percent of the liquids extracted from the play since 1980. Output from this enhanced-recovery technique will peak once the MLP has injected an equivalent amount of water to previous production. Management estimates that the field’s gross output will exceed 1,500 barrels of oil equivalent per day once this occurs.

These water-flooding projects can extend a field’s productive life by more than a decade. Mid-Con Energy Partners began pumping water into the Southeast Hewitt Unit in June 1997, 18 years after the field was first discovered. Output from the field began to tick up in November 1997. Management estimates that the volume of water pumped into the field represents about 98 percent of extracted resources. Production from the field peaked in 2010–about 13 years after secondary production began.

Mid-Con Energy Partners also has ample opportunity to grow its output and cash flow through acquisitions. The MLP has formed two limited liability companies (LLC) with Yorktown Partners, a private-equity firm that focuses on energy-related assets and owns Mid-Con Energy Partners’ general partner. These LLCs will acquire properties where producers are already using water-flooding to enhance output and acreage that appears well-suited for this approach.

Mid-Con Energy Partners’ management team initiated almost one-quarter of all water-flooding projects in Oklahoma over the past six years, which inspires confidence in the firm’s ability to identify lucrative bolt-on acquisitions. In addition, Yorktown Partners, which has about $3 billion in assets under management, has already invested in a number of oil- and gas-producing properties that might be a good fit for Mid-Con Energy Partners.

By dropping down a new water-flooding project to Mid-Con Energy Partners, Yorktown Partners would be able to immediately monetize this asset and shield ongoing revenue from the field from corporate taxation. Meanwhile, rising production and cash flow from the dropped-down asset would enable Mid-Con Energy Partners to grow its distribution. With an almost 50 percent stake in Mid-Con Energy Partners’ outstanding units, Yorktown Partners has ample incentive to pursue strategies that will foster the MLP’s growth.

Hedges help to insulate the partnership from fluctuations in commodity prices. Management aims to hedge between 50 and 80 percent of total production over a rolling three- to five-year period. At present, the MLP has hedged about 53 percent of its 2012 production and 30 percent of 2013 production, locking in prices of about $100 per barrel.  

Although Mid-Con Energy Partners’ hedge book isn’t as comprehensive as that of Growth Portfolio holding Linn Energy LLC (NSDQ: LINE), the MLP’s exposure to rising oil prices could bolster cash flow.

Mid-Con Energy Partners plans to pay a minimum quarterly distribution of $0.475 per unit, equivalent to a 12-month yield of approximately 9 percent. The MLP pays its general partner 2 percent of any distributable cash flow.

Management estimates that the MLP will generate enough cash flow to cover its full-year 2012 minimum distributions by a healthy 1.2 times. However, this projection assumes that the partnership will grow it production by roughly 80 percent and that crude oil prices will average about $96 per barrel. Based on the firm’s production history, these estimates don’t appear overly aggressive, though cash flow could take a hit if oil prices tumble.

Mid-Con Energy Partners has no exposure to depressed natural gas prices and unhedged exposure to oil prices, a positioning that works well in the current environment. At the same time, a correction in oil prices would weigh on the MLP’s cash flow. The units offer a higher-than-average yield to offset this risk. Mid-Con Energy Partners LP rates a buy under 24.

4. Pacific Drilling (NYSE: PACD), profiled in Going Deep, also joins the Higher-Risk segment of my Best Buys list.

5. Investors should also cover their short position in Diamond Offshore Drilling (NYSE: DO) for a loss of 6.3 percent. The company’s fleet of older rigs is disadvantaged in the current environment, leaving the stock with little room for upside. But the stock could enjoy a bump if day rates on deepwater drilling rigs ticks up. Investors should still avoid Diamond Offshore Drilling.

6. I am cutting recommendation Knightsbridge Tankers (NSDQ: VLCCF) to a hold and removing the stock from my Best Buys list. The company owns a fleet of oil tankers and dry-bulk carriers that transport iron ore, grains and other commodities.

The charter rates for both tankers and dry-bulk ships have weakened in recent quarters because of a persistent oversupply. The problem isn’t a lack of demand; rather, shipping firms ordered too many new ships during the 2004-07 boom years, and a glut of new ships is now entering the market.

Knightsbridge Tankers is insulated from the risk of near-term weakness in rates by its long-term charter contracts. These lease agreements signed should enable the ship owner to maintain its $0.50 quarterly dividend through at least the end of 2013. That’s equivalent to a yield of about 13.4 percent at current prices.

But the stock will tread water at best until sentiment toward the tanker industry improves. For that to happen, ship owners will need to scrap some of their fleet. We expect the tanker market to remain oversupplied until 2015. An investment in Knightsbridge Tankers will be dead money until that happens. 

The Big Four’s fourth-quarter results and related conference calls also revealed that the boom in deepwater drilling has accelerated much more rapidly than most industry observers had expected three to six months ago. Well complexity and service intensity go hand in hand; an upsurge in deepwater drilling could be a boon for oil service providers.

Management teams from Halliburton (NYSE: HAL) and Growth Portfolio holding Schlumberger (NYSE: SLB) cited a series of pre-salt discoveries offshore Angola as a catalyst for the upsurge in deepwater activity.

On Dec. 20, 2011, Cobalt International Energy (NYSE: CIE) announced an oil discovery at its Cameia-1 well in Block 21 offshore Angola. The company is preparing the well for a production test that will provide further insight into the well’s potential. With an active drilling program in each of its three Angolan pre-salt blocks, expect Cobalt International Energy to issue more press releases about potential finds. All of these discoveries will require deepwater drilling rigs to be delineated and produced.

In early January 2012, A.P. Moller Maersk’s (Copenhagen: MAERSK B) oil unit announced that its 17,500-foot Azul-1 exploration well encountered crude oil in Block 23 of the Kwanza basin. Initial assessments indicate that the well has the potential to flow more than 3,000 barrels of oil per day. A.P. Moller Maersk will need to do additional appraisal work to learn more about the field and the potential resources therein.

These announcements come on the heels of sizable deepwater discoveries by Anadarko Petroleum Corp (NYSE: APC), Kosmos Energy (NYSE: KOS) Tullow Oil (LSE: TLW) off the coasts of Ghana and Sierra Leone. (See the July 20, 2011, issue of The Energy Strategist, Africa: Oil’s Final Frontier.)

Statoil (Oslo: STL, NYSE: STO) announced a pair of major oil discoveries–Skrugard and Havis–over the past year that may hold the equivalent of 600 million barrels of crude oil. With an ambitious plan to expand its oil production 32 percent by 2020, Norway’s state-run oil company will be active in the deepwater.  

Investors also shouldn’t overlook the deepwater Gulf of Mexico. Drilling activity in the Gulf cratered because of the Macondo oil spill and subsequent moratorium on new deepwater drilling. Well permitting also slowed to a crawl after the ban was lifted.

But drilling activity in the Gulf of Mexico continues to recover. During Schlumberger’s conference call to discuss fourth-quarter earnings, CEO Paal Kibsgaard told analysts that the rig count in the region could return to pre-Macondo levels by the end of 2012:

Analyst: So you’d mentioned that your outlook for North American rig count’s flat this year, and you also said in your release that, basically, revenue was in line with the rig count, so it would seem to me that the upside here for you guys is really going to be in the Gulf of Mexico. And I was just wondering, if we strip out the strength of the seismic side, I’m curious as to where you are in your deepwater operations in the Gulf.

Are you back to the pre-Macondo levels? Are costs now fully absorbed in that market? And I guess I’m just wondering, are your margins now in the Gulf higher than in your U.S. land business?

Paal Kibsgaard: Yes, the simple answer to that is yes. This quarter, I think, was the first quarter where our Gulf of Mexico margins were accretive to North America. So, obviously, there’s been a lot of focus in on the multi-client sales for Q4, which was quite strong, but I think it’s also important to point out the strength we have on the deepwater side for well operations, both wireline and on the drilling segment. So we are quite optimistic in terms of the outlook for the Gulf of Mexico; firstly, in terms of our market share position, and in addition to how well we can leverage our high-end technology and operational performance in this type of market. So we see steady growth in deepwater drilling rig counts during 2012, roughly about a rig a month. So we would be at pre-Macondo levels for drilling rigs in the deepwater by the latter part of 2012.

Schlumberger traditionally has been one of the leading services company in the Gulf of Mexico. If the rig count in the region recovers to pre-Macondo levels by the end of 2012, that would be a huge boon for Schlumberger.

These major discoveries, coupled with a recovery in the Gulf of Mexico and Brazil’s ongoing investments in offshore production, have tightened the supply-demand balance for deepwater drilling rigs, especially the ultra-deepwater units. In the past few weeks, several contract drillers announced impressive fixtures.

• Royal Dutch Shell (NYSE: RDS A) hired Noble Corp’s (NYSE: NE) Jim Day, a semisubmersible drilling rig capable of operating in water up to 12,000 feet deep, to work in the Gulf of Mexico from January 2012 to January 2016. The international oil company will pay $530,000 per day. The contract also includes a 15 percent bonus if the rig meets certain performance goals, which brings the potential day rate to $610,000. The rig’s current contract features a day rate of $485,000.
• On Jan. 19, 2012, Aggressive Portfolio holding SeaDrill (NYSE: SDRL) announced that Royal Dutch Shell had extended its contract for the deepwater drillship West Navigator by 18 months. The new deal is worth about $320 million, which amounts to slightly less than $600,000 per day.
• On Jan. 31, 2012, Ensco (NYSE: ESV) announced that a customer had booked one of its newly built deepwater rigs under a two-and-a-half-year contract in the deepwater Gulf of Mexico. The day rate on this contract is $530,000.
• Rumors are swirling that SeaDrill rejected an offer from Total (Paris: FP, NYSE: TOT) to book the West Polaris at a day rate of $625,000 for two years or $575,000 for four years.

This recent spate of rig commitments suggest that E&P firms are eager to lock up the few remaining rigs that are available in 2012 and 2013. The day-rates in some fixtures could easily exceed $600,000–one of the reasons that SeaDrill may have held out on Total.

Rising day rates on deepwater drilling rigs bodes well for margin expansion in international markets. CEO Pall Kibsgaard explained why rising day rates are bullish for Schlumberger during a conference call on Jan. 20, 2012:

Analyst: [T]he deepwater rigs are becoming, again, very, very scarce. You highlighted what’s going on in Angola pre-salt and the potential demand there. With rates maybe pushing back to $600,000 again, historically, those have been levels where oil companies really start paying attention to technology that can improve reliability or technology that can shorten cycle time, and yet you don’t really talk about pricing. So could you help us a little bit with how you view the tightness in the rig market and the higher rates impacting either the service quality for pricing or whether it’s the standard technology or whether it’s new technology?

Paal Kibsgaard: Yes, and like I said in the previous question, I think there is typically a lag between the moves in the rig rates and the moves in our service pricing, so I think that’s the first point. But to your point in terms of what our customers are looking for, I think, like I said, there’s a growing focus on operational performance. Obviously, that is even more where the rig rates are high, like in deepwater, but we also see that in more conventional offshore operations as well.

Playing the Deepwater Boom

Among the Big Four oil services companies, Schlumberger has the most upside leverage to increased spending and pricing for deepwater contracts. The company’s WesternGeco division performs seismic surveys of offshore reservoirs, using sound and pressure waves to map subsea rock formations.

Seismic operators generally have two basic product lines: multi-client surveys and contract surveys.

Multi-client surveys typically provide data on a large area that’s prospective for oil and gas. Exploration and production firms often purchase multi-client surveys to evaluate offshore licenses coming up for auction.

Contract surveys, on the other hand, are typically completed on demand and focus on a specific portion of a field. Producers might use this information to identify specific high-probability drilling targets or to help formulate a plan to extract oil and gas from a play.

Demand for seismic data tends to pick up when deepwater exploration and development accelerates. WesternGeco reported that its backlog of unfinished seismic work increased to $1 billion in the fourth quarter of 2011, up from $850 million at the end of the third quarter.

Management also expects the segment to post strong utilization rates through the first nine months of 2012, thanks to robust demand in Angola, the Gulf of Mexico, the Arctic and the North Sea. The US Bureau of Ocean Energy Management will auction leases in the Central Gulf of Mexico around midyear–the agency has yet to announce the official date. This highly anticipated auction should bolster sales of multi-client surveys among potential bidders.

As a result of this growing backlog and planned new projects, Schlumberger has suggested that pricing for seismic services could increase by mid-2012.

A tightening market for seismic services also bodes well for Aggressive Portfolio holding Petroleum Geo-Services (Oslo: PGS, OTC: PGSVY). At the company’s recent capital markets day, management noted that only three advanced vessels capable of collecting 3-D data will join the global fleet in 2012, compared to six in the previous year.

Petroleum Geo-Services has reduced its debt burden from about $1.2 billion in 2008 to about $400 million. Management also emphasized that the firm will begin paying a dividend equal to about 25 percent to 50 percent of its net income. These payouts will likely be modest at first, but could grow substantially if the market for seismic data tightens. Buy Petroleum Geo-Services’ American depositary receipt under USD17.50.

The most direct play on rising rates for deepwater rigs is, of course, the deepwater contract drillers. Contract drillers own fleets of rigs and lease those rigs to operators for a daily fee known as a rig rate; as I noted earlier, the day-rates for the most advanced deepwater rigs are currently close to $600,000 are rising rapidly.

Deepwater contract drillers represent the best bet on rising day rates. We prefer SeaDrill, which owns the youngest and most advanced fleet of deepwater and ultra-deepwater rigs in the business. As producers increasingly favor newer, higher-specification models after the Macondo oil spill, SeaDrill has a substantial competitive advantage. Younger rigs also tend to experience less downtime.

SeaDrill’s basic business model is to build a backlog of long-term fixtures for its deepwater rigs. With the rigs locked into multiyear contracts at fixed day-rates, the company has a stable source of cash flow to support its  ample quarterly dividend of $0.76 per share. The company has the scope to raise the dividend in coming quarters.  

SeaDrill has one deepwater rig–the West Polaris drillship–slated to come off contract in October. The rig currently earns $611,000 per day, and rumors abound that SeaDrill rejected an offer of $625,000 per day from Total. If SeaDrill books this rig under a lucrative long-term deal, expect the company to raise the dividend.

SeaDrill has three rigs available in 2013: the West Leo, West Auriga and West Navigator. Given the recent uptick in day-rates, these uncommitted rigs represent a significant opportunity for SeaDrill to grow its cash flow. SeaDrill now rates a buy up to 45.

Investors should also consider Pacific Drilling (NYSE: PACD), the latest addition to the Aggressive Portfolio. The company owns a fleet of four newly built ultra-deepwater drillships and will receive two additional rigs in 2013. These state-of-the-art vessels are capable of drilling in water depths of 10,000 feet to 12,000 feet and to a total well depth of 40,000 feet, making them suitable for a wide range of jobs.

The firm has already booked its fleet under favorable long-term contracts. The Pacific Bora was delivered in mid-2011 and secured a contract with Chevron Corp (NYSE: CVX) in Nigeria that expires in late 2014 and amounts to a day rate of $475,000. Total booked the Pacific Scirocco through the end of 2012 at a day rate of $470,000 and has an option to extend the contract for another four years.

The Pacific Mistral is now under contract to Petrobras (NYSE: PBR A) through 2013 at a day rate of $458,000, while the Pacific Santa Ana will start a five-year contract with Chevron in spring 2012 at a day rate of $467,000. Pacific Drilling secured these fixtures months ago, when prevailing day rates were a bit lower than they are today.

Pacific Drilling’s newest fleet additions, the Pacific Khamsin and the Pacific Sharav, will arrive April and September 2013, respectively. The timing couldn’t be better: Few rigs will be available at that time, so Pacific Drilling could secure day rates that are above $600,000.

With a fleet of only six rigs, booking two new rigs at much higher rates could be a major upside catalyst for the stock. As a percentage of the size of its existing fleet, no deepwater drilling contractor has more available capacity in 2013 than Pacific Drilling.

Management recently announced that the company extended an option to have Samsung Shipyard build a seventh ultra-deepwater drillship that would arrive in mid-2014.

Pacific Drilling went public in November 2011 and has yet to capture investors’ attention. As other operators sign new contracts for rigs at day rates of $600,000 or more, investors will focus on Pacific Drilling and other names that have significant uncommitted rig capacity.

Pacific Drilling likely won’t pay a dividend in 2012 but could initiate a quarterly payout in 2013 when its new deliveries should be under contract. Pacific Drilling rates a buy under 11.

The lack of pricing power in international markets continues to weigh on the Big Four. With elevated commodity prices and the international rig count up considerably from its 2008 high, one would expect the services firms to be able to raise their prices. Two factors have undercut the industry’s pricing power: the Arab Spring and vicious price competition between the major services companies.

Civil unrest delayed projects in Libya, Algeria, Tunisia and Egypt. Schlumberger (NYSE: SLB) and Weatherford International (NYSE: WFT), both of which have significant operations in Libya, had to pull out of the country during the civil war. But Libyan oil output has recovered more rapidly than many analysts expected; the country is only a year away from restoring production to prewar levels, an impressive feat.

The pricing war in international markets has weighed on the Big Four’s profit margins and offset the upsurge in drilling activity. Management teams are betting that the short-term hit to margins will be more than offset by gaining a foothold in regions where E&P activity is expected to grow dramatically in coming years.

Schlumberger CEO Paal Kibsgaard summed up the competitive dynamic best during a conference call to discuss fourth-quarter earnings:

Paal Kibsgaard: We still see competitive pricing for basic technology on large contracts, while we see some positive signs on the smaller contracts. On the large contracts, our unique high-end technology is obviously priced higher and we always have significant sell-up potential as the contracts unfold over the years. If you look at the international service pricing, typically there’s a lag between the moves in the rig rates, which we have been seeing over the last couple of quarters, and our service pricing.

So there’s a potential upside on that. But I think one reason why pricing has moved so much in the international market is the market share plays that have been going on, and I think these are potentially coming to an end.

Partly, that’s going to come down to the activity increase that we potentially will see, but I think also another key factor to this is that there is a growing customer emphasis on operational performance. I think they are fully realizing that very low service pricing typically gives very low service quality. And I think one example of this is the rate that we continue to replace competition within our Drilling & Measurement segment. In Q4 alone, the ratio of we replacing competition and them replacing us was 31 to 5, and this is basically coming down to quality and technology.

Analyst:  Sure. Is it still prudent to think of a pricing inflection internationally as being more of a positive for your 2013 margin outlook, or is this something that we potentially start to see having an impact in the second half of this year?

Paal Kibsgaard: I think it’s still too early to say. Like I said, we continue to test pricing on smaller bids. For the big bids–and there’s not really that many big bids coming up in the coming year–we’d obviously be a little bit more conservative to make sure we protect and potentially gain market share. But I think it’s too early to call it. The only thing I would say is that there was a growing focus on operational performance, and that plays very well into our strength in terms of our quality and our technology.

In this excerpt, Kibsgaard indicates that price competition becomes cutthroat on large-scale international projects, megadeals that can dramatically increase a service company’s market share in a region.

But Schlumberger has successfully pushed though price increases on smaller contracts with fewer counterbids. As Kibsgaard notes, Schlumberger’s superior technology and operational performance also enables the firm to win work and pad its margins.

From leasing a drilling rig to staffing the unit with seasoned hands, the daily costs of deepwater drilling can easily exceed $1 million. In this environment, time isn’t just money–it’s a lot of money. In this environment, a services firm that can perform its job more efficiently and on schedule can produce meaningful cost savings.

With day rates on deepwater drilling rigs on the rise, E&P firms are starting to reward service providers that can complete assignments quickly and efficiently. According to Kibsgaard, Schlumberger replaced a competitor on 31 jobs in the fourth quarter and only lost five assignments to another firm.

Encouragingly, management teams from Schlumberger and Halliburton (NYSE: HAL) agreed that weaker-than-expected margins in international markets resulted from intense competition for market share rather than overcapacity or a decline in demand. Price competition will fade as activity continues to ramp up and producers favor efficiency over price.

A meaningful turn in international margins could prove to be the catalyst that enables shares of the Big Four services firms to recover their historical price multiples. The timing of this inflection point remains murky, but Kibsgaard’s comments suggest that conditions are improving. Growth Portfolio holdings Schlumberger and Weatherford International stand to gain the most from this trend. Schlumberger rates a buy up to 100, while Weatherford International rates a buy up to 17.50.

In the first half of 2011, the Big Four benefited from tight supply-demand conditions for many key services, as frenzied drilling activity in North American shale oil and gas plays strained the industry’s capacity to meet these needs.

In particular, a shortage of pressure pumping capacity–a service critical to hydraulic fracturing–had enabled service providers to push through substantial price increases in recent years.

Hydraulic fracturing is a process whereby producers pump a liquid into a shale reservoir under such tremendous pressure that it cracks the reservoir rock. This creates channels through which hydrocarbons can travel, improving permeability. Over the past several years, US producers have honed this technique in a number of prolific shale oil and gas plays, increasing the number of fracturing “stages” along the lateral portion of a horizontal well.

Of the Big Four, Halliburton (NYSE: HAL) has the most exposure to the pressure pumping business in North America. With demand for pressure pumping outstripping capacity through much of 2010 and the first half of 2011, Halliburton benefited from a virtuous cycle of higher volumes and rising prices. These tailwinds explain why Halliburton’s stock soared 25.4 percent in the first half of 2011, while shares of Growth Portfolio holding Schlumberger (NYSE: SLB) gained only 4 percent. Shares of Baker Hughes (NYSE: BHI), which also has substantial exposure to North America, surged 27.5 percent during this six-month period.

But the outlook for the North American market remains uncertain: How depressed natural gas prices will affect overall drilling activity levels and the supply-demand balance in the pressure pumping market remains to be seen.

North American natural gas prices currently hover well below $3 per million British thermal units and are unlikely to stage a sustainable rally for at least two to three years. This bearish outlook has little to do with demand: US natural gas consumption has soared to a record high.

Source: Energy Information Administration

US natural gas demand is highly seasonal, with consumption peaking during the winter heating season. Increased use of gas in the power stack has created a second period of peak demand for the fuel in summer, when demand for air conditioning and electricity is at its highest.

To smooth out seasonal fluctuations in gas demand, our graph tracks the rolling 12-month average of monthly gas demand.

In coming years, US utilities will continue to retire older, coal-fired power plants and replace them with gas-fired facilities. Natural gas produces negligible emissions of sulfur dioxide, particulates and mercury and about one-fifth as much carbon monoxide and nitrous oxide as coal. Crucially, gas also produces about half the amount of carbon dioxide on an energy-equivalent basis.

The main driver of depressed US natural gas prices is a glut of production from recently developed shale gas fields such as the Haynesville Shale in Louisiana, the Barnett Shale near Fort Worth, Texas, and the Marcellus Shale. In 2010 the US overtook Russia as the world’s leading natural gas producer; that year the US flowed almost as much natural gas as Africa and the Middle East combined.

You’ll occasionally read claims that US natural gas reserves are overstated. Reserves are an estimate of the total volume of gas that can be produced from a given play based on two factors: the volume of gas in place and the percentage that operators can extract economically. Even a slight adjustment to assumptions about  what constitutes economical production and estimated reserves can surge.

What really matters is the rate at which a particular field produces hydrocarbons over time. Oil and gas fields typically post their strongest output growth in the early stages of development, after which production rates decline significantly as geologic pressure diminishes. For example, the first-year decline rate for a single well in the Haynesville Shale and other plays can approach 80 percent, or one-fifth of its initial production rate.

By the same token, changes in reserve estimates don’t necessarily have much bearing on actual production. Between 1993 and 2010, estimates of US oil reserves increased slightly, while oil production declined by more than 1 million barrels per day (about 12 percent). 

Investors should focus on actual production. As you can see, US natural gas production has increased substantially in recent years. This growth is even more impressive when you consider that offshore output fell precipitously in the wake of the Macondo oil spill.

Source: Energy Information Administration

Investors also shouldn’t put much stock into claims that lower gas prices will prompt producers to reduce drilling activity, leading to a decline in output.

Many operators had already shifted their emphasis from the Haynesville Shale and other dry-gas plays to oil- and natural gas liquids (NGL)-rich fields such as the Eagle Ford Shale. After an unseasonably warm winter sent natural gas prices plummeting, Chesapeake Energy Corp (NYSE: CHK)–the largest independent gas producer in the US–announced it would slash gas-focused drilling activity.

The number of rigs drilling for natural gas in the US has declined to 777 from almost 1,000 in mid-2010. Nevertheless, natural gas output continues to increase unabated.

Although operators may have reined in drilling activity, each individual well drilled in a shale field is several times more productive than a conventional well; it takes far fewer rigs to produce the same volume of gas. Moreover, operators targeting crude oil in the Permian Basin or NGLs in the Eagle Ford Shale also flow large volumes of associated natural gas. For producers with acreage in liquids-rich plays, the coproduced natural gas is an afterthought; oil and NGLs account for the majority of the profit.

Here’s where the outlook gets murky. As producers reduce drilling activity in the Haynesville Shale and other dry-gas plays, the services companies are left with excess pressure pumping capacity in these fields. Instead of reducing the price of pressure pumping in these areas, the services companies have opted to shift this idle capacity to the Eagle Ford and other oil- and NGL-laden plays.

The divergence between the gas-focused rig count and the oil-focused rig count reflects the great migration from dry-gas fields to liquids-rich regions

Source: Bloomberg

For the first time in the modern history of the US energy industry, the number of rigs drilling for crude oil has eclipsed the number of rigs drilling for natural gas.

This great migration presents several challenges for services firms

The amount of pressure pumping capacity in liquids-rich plays continues to expand, limiting the Big Four’s ability to push through prices increases. Meanwhile, pressure pumping units left behind in dry-gas plays face weak prices.

Services firms not only incur the direct cost of relocating their employees and equipments, but these assets aren’t generating any revenue during the move. Equally important, the redeployed crews must learn new operating procedures and adjust to the nuances of the particular field in which they’re working.  

Halliburton CEO David Lesar discussed these challenges during a recent conference call to discuss fourth-quarter earnings:

We have moved or are in the process of moving eight frac [hydraulic fracturing] fleets from primarily natural gas plays to liquids plays. This requires redeployment of people and equipment. It disrupts the very efficient operation, and as well is requiring us to make adjustments to our supply chain. It’s important to understand that these fleets that are moving are not looking for work, but in each case now are committed to an existing customer or one who we could not serve before, and in each case has or will displace a competitor in the liquids plays.

So while beneficial to us in the long run, these moves do not come out and do not come about without a short-term impact on our margins. First we lose the productivity of these hyper efficient 24-hour crews as they move away from locations with a solid infrastructure and a higher level of expertise. Then when they start in a new location, they’re not as efficient as they get used to new operating procedures and how their reservoir responds. And finally there is a doubling up on some costs as we generally have to use commuter crews while a local crew is changed–is trained in the new operation.

So we believe that these pressures that come from this on revenues and margins will be limited. The additional benefit we get from these moves is that even more of our revenue will be generated in the liquids plays where we still have the ability to increase prices, which will help to offset inflation pressure.

Halliburton’s fourth-quarter revenue grew 6 percent from year-ago levels, driven by robust liquids-rich shale plays. However, the firm’s net income declined in North America because of margin contraction. Management expects the firm’s North American margins to fall by another 100 basis points (1 percent) in the first quarter of 2012 because of mobilization costs and related inefficiencies.

Lesar and his team also emphasized they don’t foresee a collapse in profit margins, predicting that these temporary cost pressures would abate once the fracturing crews acclimate to their new surroundings. However, when asked what a “normal” profit margin would be in North America, management responded that it’s too early to tell when these effects will smooth out. The company also doesn’t plan to add pressure pumping capacity in 2012–the first time in several years.

These developments all suggest that margin growth in North America has stalled out for at least the time being.

Schlumberger CEO Paal Kibsgaard acknowledged as much during the Q-and-A portion of a conference call on Jan. 20, 2012:

Analyst: Appreciate your outlook comments, as always, Paal, but given this dramatic falloff in natural gas prices in the U.S. and subsequent concerns about E&P cash flows, if I could ask you to start in focusing on North American land. You’ve been clear about your strategy of reestablishing yourselves here and you’ve just given your outlook for a flat rig count, but does this very quickly deteriorating outlook for gas–is it influencing recent contracting behavior in U.S. land? And then I’ll just give you my follow-up now, which is that is it influencing your behavior, whether it’s from a contracting link standpoint or a CapEx [capital expenditure] standpoint? Are there any changes that you’re making now?

Paal Kibsgaard: Well, if you look at pressure pumping pricing levels, as I said, we continue to see downward pressure on pricing in gas in Q4. The liquid basins, we saw pricing basically being flat, some contracts being up and some contracts being down. Now, how this is going to go to hold, I think, is still uncertain at this stage, right? There is obviously a chance that the continued flux of capacity from the gas basins into the liquid basins is going to have an impact on liquids pricing as well. We haven’t really seen any downwards trend yet, but clearly, over the past quarter, the pricing has been flat. So that’s basically where we stand on that.

In this excerpt, Kibsgaard notes that prices for pressure pumping services remained flat in liquids-rich plays and acknowledges that the influx of capacity will have an impact on future prices.

My outlook for the North American market: Activity and margins won’t collapse, but investors shouldn’t expect the region to drive earnings growth in coming quarters.

These lowered expectations for North America have manifested themselves in the stock market. Shares of Schlumberger and Weatherford International (NYSE: WFT)–both of which have more exposure to international markets–rallied an average of 17.4 percent in the fourth quarter. On the other hand, shares of Halliburton and Baker Hughes, which have more exposure to the US onshore market, gained an average of 9.6 percent.

Based on these developments, I’m cutting Baker Hughes to a hold.