The Final Frontier
The broader US market averages continue to languish not far off their 2008 lows, and the picture in overseas markets isn’t much better. In this weak tape, energy stocks have been notable outperformers, both in a relative and absolute sense.
That’s particularly true for the natural gas-levered stocks I’ve been highlighting over the past few issues. Although the financial media continues to focus on oil, natural gas prices are actually up about five times as much in percentage terms this year. I’m increasingly convinced that the long bear market in natural gas and gas-levered stocks is now over; there’s more upside for these stocks this year.
More broadly, the basic problem plaguing this market is continued fear of a global economic slowdown. As I explained in the Jan. 23 issue, Strengthening Headwinds, there are legitimate concerns surrounding the outlook for the US economy.
In fact, the leading economic indicators (LEI) metric I outlined in that issue continues to sit in negative territory, down 1.5 percent year-over-year. As I’ve stated before, I believe the US will see a recession this year.
The good news is that opportunities now abound for investors in energy stocks. Strong inflation numbers continue to support commodity prices, and growth in energy demand overseas has remained resilient even as the US weakens. The energy space has the scope to outperform because it’s one of the only sectors that can continue to show impressive growth even in the context of broader economic malaise.
Better still, some energy names, hit during the broad January selloff, are now at irresistible levels from a valuation standpoint and have begun to see renewed buying interest. Now is the time to start some selective buying.
I’ll also take a closer look at a handful of companies that look poised to profit from the explosion in spending on deepwater exploration and production (E&P).
Brazil looks capable of passing Venezuela as the largest oil producer in South America by 2013. A new field discovery off the coast of Rio de Janeiro will play a key part. See South of Rio.
Although the Tupi find is certainly important, there’s more to the figures being thrown around than you might realize. I shed some perspective on these numbers here. See Reserves Aren’t Production.
Petrobras appears confident in the production capabilities of both Tupi and Jupiter, both because of its revised strategic review and its increased interest in locking in rigs. See Beyond Tupi.
In addition to Petrobras itself, there are several other companies, some of which are already held in the portfolios, that have exposure to this industry. I’m also adding a new holding. See How to Play It.
Several portfolio companies have made the news lately, either through quarterly reports or other items of note. Here’s a rundown. See Portfolio Update.
I’m recommending or reiterating my recommendation in the following stocks:
Brazil is already the second-largest oil producer in South America, behind only Venezuela. (See the chart “Top South American Oil Producers.”) And if the current trends pan out, Brazil is likely to surpass Venezuela in total oil production within three to five years.
Source: Energy Information Administration (EIA)
Venezuela’s oil production is actually in decline, having fallen from 3.5 million barrels per day in 1997 to barely 2.8 million a decade later. Moreover, many of Venezuela’s key fields have high decline rates, with production dropping as much as 25 percent annually.
To stave off those severe decline rates requires heavy, ongoing maintenance and capital spending. According to the Energy Information Administration (EIA), expenditures of at least $3 billion per year are needed just to maintain current production.
At the same time, the Venezuelan government depends on oil for half of its revenues. All too often cash is siphoned off for government projects rather than reinvested in production capacity.
Investment flows into Venezuela have been further troubled by the policies of the Chavez government. Many of the largest, most-complex energy development projects in Venezuela were pursued as partnerships between foreign oil firms and the network operations center (NOC), PDVSA. The country decided to nationalize the energy industry, and the state now demands that PDVSA take on a larger majority stake in new projects; in fact, the government required foreign oil companies to give up significant stakes in existing partnerships.
The result of this power grab was two US oil giants, ExxonMobil and ConocoPhillips, exited the nation entirely. But even for those companies such as Chevron Corp that decided to remain and continue operating in Venezuela, it’s highly likely that the flow of foreign investment into oil projects will be limited in coming years. This will further crimp production.
The situation in Brazil is totally different. Petrobras is 55 percent state-owned.
That said, the Brazilian state has been far more market and investor friendly in regard to foreign investment. Brazil has also been far more aggressive in terms of targeting production growth from its fields, funding new exploration and development projects, and securing key services and infrastructure assets.
Unlike most oil-producing countries, Brazil derives very little of its roughly 2 million barrels per day of oil production from onshore and shallow-water fields. Petrobras accounts for 95 percent of the nation’s oil production; in 2006, the company produced 5 percent of its oil from waters more than 1,500 meters (4,920 feet) deep. This is considered an ultra-deepwater well.
The firm garnered another 62 percent of production from water between 300 and 1,500 meters (985 and 4,920 feet) deep, which is considered a deepwater well. That leaves only about 17 percent of production each from onshore and shallow-water fields.
Brazil’s dependence on deepwater fields is nothing new, but these fields have become more important in recent years. Check out the chart “Petrobras Offshore Production.”
Source: Petrobras
This chart shows the percentage of Petrobras’ overall oil and natural gas production to come from offshore. It’s clear this ratio has been rising sharply over the past decade from less than 75 percent of the total in 1995 to close to 90 percent today. Note the discrepancy between this chart and the figures I noted above is due to the fact that the chart includes both oil and natural gas production in terms of barrels of oil equivalent production.
Moreover, the vast majority of the company’s exploration work and new field developments are focused on deepwater and, in particular, ultra-deepwater wells. The percentage of production from such plays looks likely to rise sharply in coming years.
The majority of Brazil’s oil production comes from deepwater fields located in the Campos and Santos basins. The Campos is the larger of those two basins at this time in production terms, though, as I’ll detail later on; the Santos is home to some of the most exciting new discoveries. As the map below shows, these basins are located off the nation’s southeast coast, offshore from Rio de Janeiro.
Source: Petrobras
Despite Brazil’s vast offshore fields, the country has traditionally been a net importer of oil. In fact, early in its history, Petrobras’ main job wasn’t producing oil but coordinating and ensuring adequate imports.
As recently as 2000, Brazil imported close to 800,000 barrels of oil per day; that’s equivalent to more than a third of the country’s 2.1 million barrels per day of domestic demand. Check out the chart below for a closer look.
Source: BP Statistical Review of World Energy 2007
This chart shows Brazilian production and consumption of crude going back to 1965. The wider the gap between these two lines, the higher Brazil’s dependence on imports. It’s clear from this chart that Brazil’s import demand has been significant for most of its history.
But note in the chart what’s been happening over the last few years: Production has been rising at a faster pace than consumption. The government has long held the ambitious goal of developing Brazil’s reserves so that the country is no longer dependent on imports. That goal will soon become reality; this year, Brazil is set to become a net oil exporter thanks to a series of new offshore projects.
Petrobras has been among the most aggressive NOCs in investing capital to develop reserves. That raft of investment started to pay off over the past few years as it opened up a series of offshore oil and gas production projects. For the most part, these are fields produced using subsea technologies and so-called hub-and-spoke construction.
I explained this concept in depth in the Dec. 5, 2007, issue, Engineering and Construction. To summarize, it’s expensive and time-consuming to build new floating offshore oil and gas platforms, so building a dedicated platform for a specific project would require a very large reserve target. Otherwise, the cost of building the platform would render the project uneconomic.
But there’s an alternative. Companies can build a single floating platform to collect, store and process oil and gas production from multiple fields and many wells. Each of these wells can be produced using subsea equipment that’s installed directly on the seafloor. This equipment would include a series of valves and pipes that can be controlled remotely by the producer.
Oil and gas produced from these far-flung fields is then transported by subsea pipe to a single floating platform. Brazil added five new floating production, storage and offloading (FPSO) platforms in 2007 alone and has indicated it plans to build a lot more over the next decade.
In the table below, I highlight some of the major oilfield projects Brazil has recently opened offshore and their contribution to production in terms of offshore production. Last year, Petrobras published its 2008 to 2012 strategic business plan, outlining a schedule of projects for completion over the next few years. These projects are also noted in the table.
Source: Energy Information Administration (EIA), Petrobras, Oil & Gas Journal
It’s clear that many of the projects on this table are new fields Petrobras has found and tested; the firm now plans to put these fields into production. Some, such as Albacora and Barracuda, are existing fields where Petrobras intends to enhance production.
In the case of Alborcora, Petrobras plans to reinject water into the reservoir to re-pressurize the field. Water injection is a common technique to enhance production from more mature fields. Barracuda infill drilling involves drilling wells more closely spaced together in an attempt to increase overall production.
These projects add up to more than 1.7 million barrels of new production for Brazil. Some of this production will be offset by declines from existing fields; however, in its strategic report, Petrobras still forecasts strong production over the next few years. Check out the chart “Petrobras Liquids Production 2008-2012” for a closer look.
Source: Petrobras
This chart shows Petrobras’ production growing by roughly 800,000 barrels per day between now and 2015. However, as I noted above, these projections were based on Petrobras’ strategic plan published last year. Not long after the ink dried on these projections, the numbers already started looking conservative because Petrobras announced a series of key new oil and natural gas discoveries.
The largest and most well publicized of these is the deepwater Tupi field. This field was first discovered in late 2006 when Petrobras dug an exploratory well on the edge of the Santos Basin about 150 kilometers off the shore of Rio de Janeiro. To confirm the find, Petrobras has done extensive seismic work and drilled a second well late last year spaced about 10 kilometers away from the first well.
The company believes that Tupi could hold as much as 7 billion to 8 billion barrels of light crude oil; this would make the field a true super giant and roughly double Brazil’s estimated 14 billion barrels in total oil and gas reserves.
But Petrobras isn’t the only company developing this field; it’s also being co-developed by Wildcatters Portfolio holding BG Group (25 percent stake) and Portugal’s Galp Energia (10 percent stake).
When reporting earnings last month, BG raised its estimates for Tupi’s size. The company had previously estimated reserves of 1.7 billion to 10 billion barrels of oil equivalent; now BG estimates the field’s size at 12 billion to 30 billion barrels or more. Petrobras hasn’t commented on these revised estimates to date.
But whether Tupi holds 10 billion or 30 billion barrels, it will be one of the largest fields ever discovered and certainly among the largest found in the past two decades. Petrobras has stated it will likely take two years to put together a production plan for Tupi; the company does plan to start a mini production test by 2011, producing as much as 100,000 barrels per day. BG indicated that the fields could eventually produce as much as 1 million barrels per day at peak production levels.
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But temper your enthusiasm slightly; reserves can be a misleading concept. The basic misconception seems to be that the world consumes about 83 million barrels per day of oil or 30 billion barrels per year. Therefore, some conclude that a 30 billion barrel reserve is enough to replace a year’s worth of the world’s oil.
But that’s totally the wrong way to look at it. First, the reserve estimates you often hear quoted in the news are for estimates of original oil in place (OOIP), the total amount of oil contained in the reservoir. But, as I noted in the Feb. 20 issue, Growing Unconventionally, oil and gas aren’t found in giant underground caves or lakes but trapped in the pores of rocks.
Some of this oil is stranded in sections of the field where the rock is impermeable, and therefore, the oil can’t reach the wellbore. And some of the oil will simply be left behind during production; there’s no way to “pump” it out as if it were in storage.
Typically, a producer won’t recover anything close to 100 percent of the OOIP even after many decades of production. Some reservoirs with lower permeability may only yield 15 percent of the OOIP. And even the best, most permeable and most heavily developed fields in the world rarely reach a 70 percent recovery factor.
The estimates I’ve outlined for Tupi are for total hydrocarbons in place, not the actual reserves that can or will be recovered. This recovery factor is likely one aspect of the field Petrobras will be studying in more depth as it formulates its development plan.
The second point is that it’s not size of the reserve that matters but the speed at which it can be produced. This is typically a function of the pressures within the reservoir that drive production. To make a long story short, check out the chart “UK and Norwegian Oil Production” below.
Source: BP Statistical Review of World Energy 2007
Production of oil from these two countries approximates North Sea oil production. The UK’s two major fields, Brent and Forties, went into production in 1975 and 1977, respectively. Norway’s major fields started going into production in the early 1970s and underwent major rehabilitation programs to boost production in the ’80s.
At any rate, the chart shows that, not long after these giant fields entered production, North Sea oil production began to soar. The initial growth in production was rapid; the North Sea finally entered a sort of plateau period in 1995. Production peaked early this decade and has since fallen precipitously.
Although these fields will still be yielding oil (and gas) for many years to come, the production rate will continue to fall. That’s despite the fact that some estimate that many North Sea oilfields still contain 70 percent of their OOIP.
Most fields follow some version of this “bell curve” production profile. In other words, production ramps up quickly when a field is first produced because underground pressures are high; natural geologic forces drive production.
But at some point, as pressures fall, production hits a plateau. This occurs long before all the OOIP is recovered. At this point, the producer can use certain techniques–such as oil and/or gas injection–to stabilize pressures and increase production. However, these factors are unlikely to do much more than simply stabilize production at relatively high levels.
My bottom line with this digression is that, even though Tupi may have OOIP of 30 billion barrels, current estimates are that it will see peak production of perhaps 1 million to 1.5 million barrels per day. That peak production rate would likely occur sometimes toward the end of the coming decade.
Of course, 1 million to 1.5 million barrels per day in the context of an 83-million-barrel-per-day market sounds less impressive than 30 billion barrels in reserves. But in many ways, it’s a more meaningful figure.
Once again, I don’t say this to belittle the Tupi discovery; it’s an extremely important and impressive find. However, it’s worth countering some of the sensationalist ramblings I’ve heard recently from the media about Tupi.
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Jupiter isn’t Brazil’s only gas field by any stretch of the imagination. In fact, natural gas is another major focus of Brazil’s deepwater exploration program. Just as with oil, Brazil has traditionally been reliant on imports to meet natural gas demand. See the chart “Brazil Gas Production and Consumption.”
Source: BP Statistical Review of World Energy 2007
But Petrobras has been bringing a series of new gas projects online over the past few years, just as with oil. And some major new developments are planned in 2008 and 2009. The largest of these deals is the Mexilhao field, due to come online in 2009. This single field is expected to produce 15 million cubic meters of gas per day, equivalent to 30 percent of total Brazilian supply.
All told, estimates suggest that Brazilian gas supply will expand from 28 million cubic meters per day in 2007 to more than 70 million cubic meters by 2010. And that doesn’t even account for the effects of newly discovered fields like Jupiter that weren’t included in Petrobras’ 2007 strategic review and outlook.
Brazil’s deepwater production growth potential for both oil and natural gas was impressive enough before the discovery of giant fields like Tupi and Jupiter in the Santos Basin. But Petrobras has additional large-scale exploration efforts underway in the Santos Basin; it’s quite possible the company will discover more significant fields that have the potential to generate production growth far above the estimates it published just a few short months ago.
In fact, current estimates are that Brazil could produce close to 4.5 million barrels per day in 2015, when comparatively Tupi was slated to produce roughly 3 million barrels per day in prior estimates.
And Brazil has certainly put the capital spending plans in place to fund an impressive exploration and development program. Consider that, in its strategic plan, Petrobras budgeted $112.4 billion in capital spending for the 2008-12 period. Of that total, Petrobras planned to spend some $11.6 billion on exploration and $53.5 billion on producing existing and newly discovered field development. The company also planned for another nearly $30 billion in spending on new refineries.
But, as noted above, this strategic plan was published before the Tupi and Jupiter finds. More recently, the company has said it plans to spend $12 billion by 2012 on further exploration in the Santos Basin, home to both Jupiter and Tupi, alone.
Consider that, in 2006, Petrobras announced plans to spend a total of $87.1 billion between 2007 and 2011. A year later, the firm boosted its four-year capital spending plans by close to 30 percent. That’s proof that Petrobras is willing to spend big on developing new fields and projects.
It’s also worth noting that Petrobras has locked a total of 30 deepwater and ultra-deepwater drilling rigs under contracts with major contract drilling firms. As I explained at some length in the Feb. 6 issue, Earnings on Tap, the global supply of deepwater rigs is extraordinarily tight right now. There simply aren’t enough rigs to meet demand for new project developments. Day-rates–the daily fee for hiring a rig–have risen to more than $600,000 per day for the most capable rigs, up from the $200,000 range earlier this decade.
In fact, Petrobras has locked in contracts on the largest number of deepwater and ultra-deepwater drilling rigs of any producer. The firms with the next largest contracted fleets, BP and Statoil, have 13 rigs each.
And Petrobras recently asked for quotes on three- to five-year contract deals on rigs starting in 2011. The company is keen to ensure that it has plenty of rigs to handle all its planned drilling and exploration projects.
If anything, Petrobras’ interest in securing rigs for after 2011 has picked up notably since the Tupi and Jupiter discoveries. The company has now been trying to secure ultra-deepwater rigs for 10-year contracts—a far longer-than-normal term—to produce these fields. This further suggests Petrobras is confident in the size and scale of these fields.
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One way to play the country’s energy growth potential is through Petrobras. Not only is the company involved in most of the current, upcoming oil and gas projects in Brazil, but it’s also widely regarded as the best-run NOC.
Petrobras was quick to book deepwater drilling rigs and has been willing to invest in its oil sector to fund future growth–both good signs that management thinks ahead. After all, many big producers who failed to book out rig capacity are now struggling to secure rigs to handle new their proposed projects.
As I noted above, Petrobras is just at the leading edge of a new production boom as it brings new deepwater projects on line gradually to 2012. Another catalyst for Petrobras’ stock is likely further announcements regarding Tupi, including an eventual plan and timetable outlining how the field is going to be developed.
As I highlighted in the most recent issue, production growth typically drives performance for E&P firms and the integrated oils. The same is true of Petrobras.
My only issue with Petrobras is valuation. Its shares have run up a great deal in the past year and a half, from under $40 in late 2006 to more than $120 earlier this year.
At this time, Petrobras looks expensive relative to the integrated oils like Chevron and Exxon; those two stocks currently trade at 9.4 times and 11.1 times, respectively, this year’s earnings estimates, while Petrobras trades at 14.5 times. On a price-to-cash-flow basis, the country trades at 9.8 times against 9.3 times for ExxonMobil and 7.4 times for Chevron.
Petrobras deserves to trade at a premium valuation because it has far higher production growth potential than most of the integrated oil companies. And as an NOC, Petrobras has greater access to reserves. I also don’t believe that any sort of political discount is warranted because Brazil’s regulatory climate in relation to the energy industry has been among the most stable in the world.
All that said, the current valuation premium looks steep. I’ve mentioned Petrobras before in TES and have long held it as a buy in the How They Rate Table. I’ll continue to track it there for now and may add it to the main portfolios on a pullback.
There’s no doubt that Petrobras is one of the world’s best-positioned producers and rates a buy for longer-term investors willing to ride out some fairly volatile swings from time to time.
Also note that the model portfolios already have exposure to the Tupi find through existing holding BG Group. BG Group is now a buy under 125.
But there are some other compelling plays on growth in Brazil’s deepwater sector. But Brazil is simply one facet of a global deepwater investment boom; offshore Africa, the Gulf of Mexico and Asia are three other markets experiencing significant growth in deepwater spending.
Longer term, the global services firms are one way to play the boom. Consider that Tupi is roughly 800 kilometers in length and 200 kilometers in width, according to Petrobras, and is in waters ranging from 2,000 to 3,000 meters deep. (That’s 6,500 to 10,000 feet.) This makes Tupi an ultra-deepwater field, which requires the most advanced rigs that are capable of drilling in the deepest waters.
But that’s only the beginning. The well Petrobras dug to produce Tupi had a total vertical length of 20,000 feet and drilled through a tough-to-drill mile-long layer of salt.
Pressures and temperatures in the well are also extreme. To produce such a well safely and effectively requires the use of the most advanced oilfield technologies; more complex field developments have higher services content. That means more work for the services firms–and more revenues.
In the Feb. 6 issue, I highlighted the services industry at some length. The only limitation on growth for some of my favorites in 2008 is a lack of deepwater rig availability. There aren’t enough deepwater rigs to meet demand, so activity isn’t accelerating as rapidly as it otherwise would. This is what many analysts have dubbed “the platform problem.”
This is the only reason I don’t currently recommend services giant Schlumberger. Next year, as new rigs go into service, the platform headwind will begin to abate. But for now, I prefer to focus elsewhere. For a full rundown of my rationale, check out that issue.
And for reasons I outlined in that issue as well, I continue to recommend Weatherford International. Although not traditionally seen as a deepwater services play, Weatherford has been performing more and more work in ultra-deepwater reservoirs, so it certainly has some exposure to this area.
A final play worth mentioning on the services front is deepwater seismic specialist CGG Veritas, a Wildcatters Portfolio holding. Seismic surveys are underground maps of rock formations used to identify promising targets for exploration.
Detailed seismic work is necessary even within existing fields to aid in well placement. After all, drilling wells in 10,000 feet of water that stretch to a total vertical length of 20,000 feet is hardly inexpensive. Producers want to make sure that their wells are placed to optimize production.
CGG Veritas has among the largest fleet of ships capable of performing such deepwater surveys. I highlighted the stock at more length in the Feb. 6 issue. CGG Veritas continues to rate a buy under 55.
Moving beyond these existing recommendations, I’m adding offshore engineering and construction (E&C) specialist Acergy (NSDQ: ACGY) to the Wildcatters Portfolio this issue.
This isn’t the first time I have written about Acergy. I dedicated the Dec. 5, 2007, issue to that industry and featured Acergy prominently.
The company specializes in subsea umbilicals, risers and flowlines, or SURF. SURF relates only to wells that are developed with subsea completions, meaning that the well is installed directly on the seafloor. This would apply primarily to deepwater developments.
It’s also important to note that SURF doesn’t just apply to new purpose-built projects. Acergy also handles subsea tieback deals, the hub-and-spoke construction projects that I noted above.
In other words, when Petrobras decides to hook a new series of deepwater wells to an existing FPSO, it needs SURF equipment installed to take production from the well–often for many miles via subsea pipeline–and then from the seafloor to the surface. Acergy installs all the pipelines, risers and unbilicals needed to connect new subsea wells to existing platforms.
Outside of SURF, Acergy also handles conventional work in the shallow water, performs maintenance and inspection work on subsea wells and pipelines, and even installs larger diameter subsea pipelines, known as trunklines, to transport hydrocarbons over longer distances. But SURF remains the key driver of results.
Acergy reported its fourth quarter earnings in Feb. 13, and overall trends in the SURF business remain rock solid. At the end of 2007, Acergy had a total backlog of unfinished projects topping $3.2 billion. This is a record backlog for the company and represents 24 percent growth over the backlog one year ago.
Better still, between the end of 2007 and the company’s conference call, Acergy noted that it’s added another $1 billion to its backlog.
The list of new projects adding to the backlog includes the giant Pazflor contract in Angola, one of the hottest deepwater markets in the world today. This award is for 46 subsea wells to be hooked up to a floating production system; the wells are found in waters up to 1,200 meters (4,000 feet) in depth.
Pazflor is being managed by European integrated oil giant Total. In addition to Pazflor, Acergy booked the Deep Panuke project in offshore Canada. That project is managed by Encana Corp and Shell’s Perdido deepwater project in the Gulf of Mexico.
In addition, Acergy completed a number of big deals in its most recent quarter, including the largest deal it’s ever undertaken: the Greater Plutonio deepwater project in Angola. Greater Plutonio is a $4 billion project BP manages that includes a series of 43 subsea wells tied back to a single floating production platform.
The wells, located in 1,200 to 1,500 feet of water, are considered deepwater wells. Just as with all its other big deepwater deals, Acergy handles the SURF installation for all these wells. The contract was worth $730 million and was awarded to Acergy and its competitor Technip, with Acergy taking the lead.
Based on the size and scope of all these awards, it’s clear that Acergy is a world leader in the SURF business. And by purchasing Acergy now, we’re getting in with an outstanding price. The company’s stock has been hit by two primary issues over the last six months: a poorly executed tax strategy and the Mexilhao Trunkline Project in Brazil.
The tax issue is a bit technical, and the specifics aren’t terribly important. Basically, the company’s tax rate soared to more than 43 percent in the fourth quarter well above the average tax rate for its peers in the 30 to 35 percent range. The problem arose from the way the company accounted for revenues and costs from some of its African contracts.
The end result was that Acergy ended up getting hit with an African withholding tax that it couldn’t recover. In addition, some of these projects were partly managed out of Acergy’s office in France, and the company also got hit by a significant tax bill from France, which has some of the highest tax rates in the world.
To combat this problem, Acergy hired a team of tax professionals who review each deal and how it’s accounted for so that this problem can be avoided in future. Management guided expectations for its full-year 2008 tax rate to just 35 percent, close to the peer group average. And there’s more room for further improvement.
The second problem relates to a trunkline deal serving the Mexilhao gas field in Brazil. A trunkline is nothing more than a subsea pipeline that connects a floating platform to the coast. In the case of Mexilhao, this was a $400 million deal to build a 120-kilometer long, 34-inch thick pipeline to transport treated gas from the Mexilhao platform to Caraguatatuba, south of Rio de Janeiro.
This contract turned into a total disaster. First, management admitted that trunklines are outside Acergy’s normal SURF core business. And second, the company tried to run the project as a joint venture between its North Sea office and its local office in Brazil. There was a delay in moving pipe-laying and other ships from the North Sea to Brazil.
To remedy the situation, Acergy was forced to negotiate with a single local contractor to perform some of the work. This was a case of a desperate client and a sole supplier; the cost was enormous. Acergy has taken some charges to reflect this problem, and the bad news from the deal is now out of the way.
In addition, Acergy has taken steps to mitigate the problem. First, the company removed most of the managers in charge of the project. Management also stated that there was a possibility it would receive a partial recovery of those inflated costs from Petrobras.
The tax and Mexihao issues are nothing new. Acergy has repeatedly explained the impacts of these missteps. That is why, even after missing estimates because of the tax problem, the stock actually rallied on the day of its report.
With these problems well-known and understood, they no longer have much of an impact on the stock. In addition, all E&C companies occasionally misstep on a single project; it’s just the nature of the business.
The good news about Acergy’s minor problems is that, if the company hadn’t faced these issues, it probably wouldn’t be trading at such an attractive valuation. Acergy trades at less than 15 times 2008 earnings estimates, less than its peer group average. That’s despite the fact that Acergy is heavily leveraged to one of the most exciting growth markets in energy: deepwater.
Over the next few years, you can expect to hear SURF awards for Petrobras’ projects, as well as for a series of new deepwater deals in Africa. Acergy stands well placed to win more than its fair share of these deals.
And its technology is absolutely crucial for deepwater developments. Acergy is added to the Wildcatters Portfolio as a buy under 24 and a stop at 15.20.
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Wildcatter EOG Resources, highlighted at length in the most recent issue, announced a potentially large natural gas find in Canada. The find is located in northeastern British Columbia and could contain as much as 6 trillion cubic feet of gas reserves. EOG offered few specifics about how much production it can garner from the play.
In addition, EOG announced a significant boost to its oil and gas production estimates. The main drivers of that bump are the Barnett and Bakken shale plays. The lift to guidance is most impressive because it comes less than one month after EOG reported earnings and issued detailed guidance on production. This suggests there could be far more upside to production estimates as the year progresses.
EOG sailed nearly 20 percent higher on this release, though it’s since pulled back a bit. Needless to say, EOG Resources is now far above its buy target of 105, so subscribers without a position should steer clear for now. The stock has been highly volatile since releasing this bullish news. I’ll consider raising the target once the stock settles down.
We were stopped out of my recommended short position in the US Oil Fund (AMEX: USO) at $80 for a loss of around 12.5 percent. This position was intended as a hedge against potential weakness in energy prices because of fears of a US economic slowdown. I outlined my case for shorting the exchange traded fund at some length in the Jan. 23 issue.
Many of the rationales I outlined for shorting oil came to pass. Check out the chart “US Crude Oil Inventories” below.
Source: EIA
Over the past four weeks, US oil imports have averaged about 750,000 barrels per day higher than in the same four-week period one month ago. Meanwhile, inventories of crude oil in storage have risen from the extraordinarily depressed levels of late in 2007 to above average today. Therefore, the supply picture isn’t bullish.
Last year, supply and demand fundamentals drove the oil markets, but this year, the main factor driving crude is the dollar. The US dollar has fallen 4.3 percent so far this year, while oil has gained almost exactly 4.3 percent. Another way to look at it is that crude oil is actually trading up well under 1 percent in euro terms this year.
This isn’t a currency trading letter, but I wouldn’t be surprised to see the dollar bounce at some point this year as it becomes clear that Europe isn’t immune to the credit crunch, and its central monetary authority will inevitably follow the Federal Reserve and cut rates aggressively. When that happens, the short-term negative fundamentals for oil prices, noted in the Jan. 23 issue, will take the driver’s seat in the oil markets.
Until then, this hedge didn’t work, and I was wrong about oil. Take the loss in the US Oil Fund, and stand aside.
Fortunately, natural gas has vastly outperformed oil this year, rallying more than 20 percent compared to less than 5 percent for oil. This has been great news for our gas turnaround plays, such as land driller Nabors Industries. I highlighted my rationale for owning this stock in the Jan. 23 issue.
The company reported results in early February that were positive across the board, and the stock rallied on that release. There are two key points worth noting from the call.
First, Nabors’ international business is growing like a weed, and execution missteps that plagued the stock last year appear to be firmly behind it. In the fourth quarter, the company landed contracts on an additional 19 land rigs in international markets at high, attractive day-rates.
And as of the end of the quarter, Nabors was bidding on another 80 international deals. Given its experience overseas and strong sales force, I suspect Nabors will get more than its fair share of these deals.
International operations are set to grow by 50 percent this year and could grow by a similar amount in 2009. International earnings before interest and tax (EBIT) accounted for 31 percent of the total in the fourth quarter; in fourth quarter 2008, international EBIT will be around 45 percent of the business. Strength here is helping offset some weakness in North America, particularly Canada.
But there’s light at the end of the North American tunnel. Nabors says that rates for its more advanced rigs are stabilizing. This is probably due to continued strong drilling activity in unconventional gas plays; operators typically used more advanced rigs to drill these wells.
And given the uptick in gas prices, Nabors’ North American operations could surprise to the upside this year. I’m raising the buy target for Nabors Industries to 33.
Australian coal miner MacArthur Coal reported interim results and hosted a conference call last week and saw a significant rally to new highs as a result.
At first glance, the report looks terrible. The company’s profits are down 68 percent year-over-year, and its net income came in at the very low end of guidance. That guidance was issued back in November. And to top it all off, the company warned that it will be difficult to meet its production forecasts for this year.
But all of this is actually bullish for MacArthur. I’ve outlined the basic situation in the coal markets on a number of occasions, including the Jan. 2 issue, Taking Stock of 2007. MacArthur is suffering from the same basic problems as Australian producers: heavy rainfall in key producing areas, coupled with extreme port congestion.
MacArthur stated that 26.8 inches of rain, which flooded the mine and curtailed production, fell on its key mine in December and January. Meanwhile, the coal export ports designed to carry coal to markets in Asia are so overcrowded that miners are having trouble exporting the coal they produce.
The upside to all this is coal prices are soaring, and MacArthur will be able to lock in prices as high as $170 per ton on Asian coal export shipments. These new contracts last a year and go into effect on April 1.
That compares to the $67 to $68 per ton MacArthur received on average in 2007. Even with production problems, the company’s profits could triple this year.
The stock is now up 94 percent in US dollar terms from my original recommendation in early September and has been above its buy target for a few weeks now. I still see the potential for more upside in the coming months.
But given how extended the stock is near term, take profits on half your position in MacArthur Coal. In other words, if you own 100 shares, sell 50 of them and hold on to the remainder of the position.
Speaking Engagements
It’s time: Vegas, baby! Neil, Roger and I will head to the desert paradise May 12-15, 2008, for the Las Vegas Money Show at Mandalay Bay. Go to http://www.lasvegasmoneyshow.com or call 800-970-4355 with priority code 010671 to do the “what happens here stays here” thing.
Back to In This Issue
That’s particularly true for the natural gas-levered stocks I’ve been highlighting over the past few issues. Although the financial media continues to focus on oil, natural gas prices are actually up about five times as much in percentage terms this year. I’m increasingly convinced that the long bear market in natural gas and gas-levered stocks is now over; there’s more upside for these stocks this year.
More broadly, the basic problem plaguing this market is continued fear of a global economic slowdown. As I explained in the Jan. 23 issue, Strengthening Headwinds, there are legitimate concerns surrounding the outlook for the US economy.
In fact, the leading economic indicators (LEI) metric I outlined in that issue continues to sit in negative territory, down 1.5 percent year-over-year. As I’ve stated before, I believe the US will see a recession this year.
The good news is that opportunities now abound for investors in energy stocks. Strong inflation numbers continue to support commodity prices, and growth in energy demand overseas has remained resilient even as the US weakens. The energy space has the scope to outperform because it’s one of the only sectors that can continue to show impressive growth even in the context of broader economic malaise.
Better still, some energy names, hit during the broad January selloff, are now at irresistible levels from a valuation standpoint and have begun to see renewed buying interest. Now is the time to start some selective buying.
In This Issue
In today’s issue, I’ll take a closer look at the outlook for deepwater oil and gas production and spending, with a particular focus on Brazil. The country is set to become one of the most important markets for deepwater in the coming years; late last year, Brazil made what’s perhaps the largest oilfield discovery of the past two decades.I’ll also take a closer look at a handful of companies that look poised to profit from the explosion in spending on deepwater exploration and production (E&P).
Brazil looks capable of passing Venezuela as the largest oil producer in South America by 2013. A new field discovery off the coast of Rio de Janeiro will play a key part. See South of Rio.
Although the Tupi find is certainly important, there’s more to the figures being thrown around than you might realize. I shed some perspective on these numbers here. See Reserves Aren’t Production.
Petrobras appears confident in the production capabilities of both Tupi and Jupiter, both because of its revised strategic review and its increased interest in locking in rigs. See Beyond Tupi.
In addition to Petrobras itself, there are several other companies, some of which are already held in the portfolios, that have exposure to this industry. I’m also adding a new holding. See How to Play It.
Several portfolio companies have made the news lately, either through quarterly reports or other items of note. Here’s a rundown. See Portfolio Update.
I’m recommending or reiterating my recommendation in the following stocks:
- Acergy (NSDQ: ACGY)
- BG Group (London: BG; OTC: BRGYY)
- Nabors Industries (NYSE: NBR)
- Petrobras (NYSE: PBR)
- EOG Resources (NYSE: EOG)
- MacArthur Coal (Australia: MCC; OTC: MACDF)
- US Oil Fund (AMEX: USO)
South of Rio
Deepwater is truly the final frontier of oilfield exploration, one of the only places where producers are still finding giant fields of untapped oil and gas. And one of the emerging superpowers of the deep is Brazil and the country’s national oil company (NOC), Petrobras (NYSE: PBR).Brazil is already the second-largest oil producer in South America, behind only Venezuela. (See the chart “Top South American Oil Producers.”) And if the current trends pan out, Brazil is likely to surpass Venezuela in total oil production within three to five years.
Source: Energy Information Administration (EIA)
Venezuela’s oil production is actually in decline, having fallen from 3.5 million barrels per day in 1997 to barely 2.8 million a decade later. Moreover, many of Venezuela’s key fields have high decline rates, with production dropping as much as 25 percent annually.
To stave off those severe decline rates requires heavy, ongoing maintenance and capital spending. According to the Energy Information Administration (EIA), expenditures of at least $3 billion per year are needed just to maintain current production.
At the same time, the Venezuelan government depends on oil for half of its revenues. All too often cash is siphoned off for government projects rather than reinvested in production capacity.
Investment flows into Venezuela have been further troubled by the policies of the Chavez government. Many of the largest, most-complex energy development projects in Venezuela were pursued as partnerships between foreign oil firms and the network operations center (NOC), PDVSA. The country decided to nationalize the energy industry, and the state now demands that PDVSA take on a larger majority stake in new projects; in fact, the government required foreign oil companies to give up significant stakes in existing partnerships.
The result of this power grab was two US oil giants, ExxonMobil and ConocoPhillips, exited the nation entirely. But even for those companies such as Chevron Corp that decided to remain and continue operating in Venezuela, it’s highly likely that the flow of foreign investment into oil projects will be limited in coming years. This will further crimp production.
The situation in Brazil is totally different. Petrobras is 55 percent state-owned.
That said, the Brazilian state has been far more market and investor friendly in regard to foreign investment. Brazil has also been far more aggressive in terms of targeting production growth from its fields, funding new exploration and development projects, and securing key services and infrastructure assets.
Unlike most oil-producing countries, Brazil derives very little of its roughly 2 million barrels per day of oil production from onshore and shallow-water fields. Petrobras accounts for 95 percent of the nation’s oil production; in 2006, the company produced 5 percent of its oil from waters more than 1,500 meters (4,920 feet) deep. This is considered an ultra-deepwater well.
The firm garnered another 62 percent of production from water between 300 and 1,500 meters (985 and 4,920 feet) deep, which is considered a deepwater well. That leaves only about 17 percent of production each from onshore and shallow-water fields.
Brazil’s dependence on deepwater fields is nothing new, but these fields have become more important in recent years. Check out the chart “Petrobras Offshore Production.”
Source: Petrobras
This chart shows the percentage of Petrobras’ overall oil and natural gas production to come from offshore. It’s clear this ratio has been rising sharply over the past decade from less than 75 percent of the total in 1995 to close to 90 percent today. Note the discrepancy between this chart and the figures I noted above is due to the fact that the chart includes both oil and natural gas production in terms of barrels of oil equivalent production.
Moreover, the vast majority of the company’s exploration work and new field developments are focused on deepwater and, in particular, ultra-deepwater wells. The percentage of production from such plays looks likely to rise sharply in coming years.
The majority of Brazil’s oil production comes from deepwater fields located in the Campos and Santos basins. The Campos is the larger of those two basins at this time in production terms, though, as I’ll detail later on; the Santos is home to some of the most exciting new discoveries. As the map below shows, these basins are located off the nation’s southeast coast, offshore from Rio de Janeiro.
Source: Petrobras
Despite Brazil’s vast offshore fields, the country has traditionally been a net importer of oil. In fact, early in its history, Petrobras’ main job wasn’t producing oil but coordinating and ensuring adequate imports.
As recently as 2000, Brazil imported close to 800,000 barrels of oil per day; that’s equivalent to more than a third of the country’s 2.1 million barrels per day of domestic demand. Check out the chart below for a closer look.
Source: BP Statistical Review of World Energy 2007
This chart shows Brazilian production and consumption of crude going back to 1965. The wider the gap between these two lines, the higher Brazil’s dependence on imports. It’s clear from this chart that Brazil’s import demand has been significant for most of its history.
But note in the chart what’s been happening over the last few years: Production has been rising at a faster pace than consumption. The government has long held the ambitious goal of developing Brazil’s reserves so that the country is no longer dependent on imports. That goal will soon become reality; this year, Brazil is set to become a net oil exporter thanks to a series of new offshore projects.
Petrobras has been among the most aggressive NOCs in investing capital to develop reserves. That raft of investment started to pay off over the past few years as it opened up a series of offshore oil and gas production projects. For the most part, these are fields produced using subsea technologies and so-called hub-and-spoke construction.
I explained this concept in depth in the Dec. 5, 2007, issue, Engineering and Construction. To summarize, it’s expensive and time-consuming to build new floating offshore oil and gas platforms, so building a dedicated platform for a specific project would require a very large reserve target. Otherwise, the cost of building the platform would render the project uneconomic.
But there’s an alternative. Companies can build a single floating platform to collect, store and process oil and gas production from multiple fields and many wells. Each of these wells can be produced using subsea equipment that’s installed directly on the seafloor. This equipment would include a series of valves and pipes that can be controlled remotely by the producer.
Oil and gas produced from these far-flung fields is then transported by subsea pipe to a single floating platform. Brazil added five new floating production, storage and offloading (FPSO) platforms in 2007 alone and has indicated it plans to build a lot more over the next decade.
In the table below, I highlight some of the major oilfield projects Brazil has recently opened offshore and their contribution to production in terms of offshore production. Last year, Petrobras published its 2008 to 2012 strategic business plan, outlining a schedule of projects for completion over the next few years. These projects are also noted in the table.
|
Petrobras’ Projects
|
||
|
Date Started
|
Project
|
Production (Barrels/Day)
|
| January 2007 | Espadarte Module 2 | 100,000 |
| October 2007 | Piranema | 30,000 |
| October 2007 | Golfinho Module 2 | 100,000 |
| November 2007 | Roncador | 180,000 |
| December 2007 | Roncador 2 | 180,000 |
| 2008 | Marlim Leste/Niteroi Jabuti | 100,000 |
| 2008 | Marlim Sul Module 2 | 180,000 |
| 2008 | Marlim Lese P-53 | 180,000 |
| 2009 | Frade | 100,000 |
| 2009 | Parque de Conchas | 100,000 |
| 2010 | Albacora (water injection) | 23,000 |
| 2010 | Barracuda (infill drilling) | 50,000 |
| 2011 | Marlim Sul Module 3 | 100,000 |
| 2012 | Espadarte Module 3 | 100,000 |
| 2012 | Jubarte | 180,000 |
| Total | 1.703 million | |
Source: Energy Information Administration (EIA), Petrobras, Oil & Gas Journal
It’s clear that many of the projects on this table are new fields Petrobras has found and tested; the firm now plans to put these fields into production. Some, such as Albacora and Barracuda, are existing fields where Petrobras intends to enhance production.
In the case of Alborcora, Petrobras plans to reinject water into the reservoir to re-pressurize the field. Water injection is a common technique to enhance production from more mature fields. Barracuda infill drilling involves drilling wells more closely spaced together in an attempt to increase overall production.
These projects add up to more than 1.7 million barrels of new production for Brazil. Some of this production will be offset by declines from existing fields; however, in its strategic report, Petrobras still forecasts strong production over the next few years. Check out the chart “Petrobras Liquids Production 2008-2012” for a closer look.
Source: Petrobras
This chart shows Petrobras’ production growing by roughly 800,000 barrels per day between now and 2015. However, as I noted above, these projections were based on Petrobras’ strategic plan published last year. Not long after the ink dried on these projections, the numbers already started looking conservative because Petrobras announced a series of key new oil and natural gas discoveries.
The largest and most well publicized of these is the deepwater Tupi field. This field was first discovered in late 2006 when Petrobras dug an exploratory well on the edge of the Santos Basin about 150 kilometers off the shore of Rio de Janeiro. To confirm the find, Petrobras has done extensive seismic work and drilled a second well late last year spaced about 10 kilometers away from the first well.
The company believes that Tupi could hold as much as 7 billion to 8 billion barrels of light crude oil; this would make the field a true super giant and roughly double Brazil’s estimated 14 billion barrels in total oil and gas reserves.
But Petrobras isn’t the only company developing this field; it’s also being co-developed by Wildcatters Portfolio holding BG Group (25 percent stake) and Portugal’s Galp Energia (10 percent stake).
When reporting earnings last month, BG raised its estimates for Tupi’s size. The company had previously estimated reserves of 1.7 billion to 10 billion barrels of oil equivalent; now BG estimates the field’s size at 12 billion to 30 billion barrels or more. Petrobras hasn’t commented on these revised estimates to date.
But whether Tupi holds 10 billion or 30 billion barrels, it will be one of the largest fields ever discovered and certainly among the largest found in the past two decades. Petrobras has stated it will likely take two years to put together a production plan for Tupi; the company does plan to start a mini production test by 2011, producing as much as 100,000 barrels per day. BG indicated that the fields could eventually produce as much as 1 million barrels per day at peak production levels.
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Reserves Aren’t Production
These all sound like big, impressive numbers, and investors shouldn’t underestimate the importance of this find. After all, Tupi could make Brazil a very important exporter. Some have conjectured that the country may eventually be asked to enter Organization of the Petroleum Exporting Countries (OPEC).But temper your enthusiasm slightly; reserves can be a misleading concept. The basic misconception seems to be that the world consumes about 83 million barrels per day of oil or 30 billion barrels per year. Therefore, some conclude that a 30 billion barrel reserve is enough to replace a year’s worth of the world’s oil.
But that’s totally the wrong way to look at it. First, the reserve estimates you often hear quoted in the news are for estimates of original oil in place (OOIP), the total amount of oil contained in the reservoir. But, as I noted in the Feb. 20 issue, Growing Unconventionally, oil and gas aren’t found in giant underground caves or lakes but trapped in the pores of rocks.
Some of this oil is stranded in sections of the field where the rock is impermeable, and therefore, the oil can’t reach the wellbore. And some of the oil will simply be left behind during production; there’s no way to “pump” it out as if it were in storage.
Typically, a producer won’t recover anything close to 100 percent of the OOIP even after many decades of production. Some reservoirs with lower permeability may only yield 15 percent of the OOIP. And even the best, most permeable and most heavily developed fields in the world rarely reach a 70 percent recovery factor.
The estimates I’ve outlined for Tupi are for total hydrocarbons in place, not the actual reserves that can or will be recovered. This recovery factor is likely one aspect of the field Petrobras will be studying in more depth as it formulates its development plan.
The second point is that it’s not size of the reserve that matters but the speed at which it can be produced. This is typically a function of the pressures within the reservoir that drive production. To make a long story short, check out the chart “UK and Norwegian Oil Production” below.
Source: BP Statistical Review of World Energy 2007
Production of oil from these two countries approximates North Sea oil production. The UK’s two major fields, Brent and Forties, went into production in 1975 and 1977, respectively. Norway’s major fields started going into production in the early 1970s and underwent major rehabilitation programs to boost production in the ’80s.
At any rate, the chart shows that, not long after these giant fields entered production, North Sea oil production began to soar. The initial growth in production was rapid; the North Sea finally entered a sort of plateau period in 1995. Production peaked early this decade and has since fallen precipitously.
Although these fields will still be yielding oil (and gas) for many years to come, the production rate will continue to fall. That’s despite the fact that some estimate that many North Sea oilfields still contain 70 percent of their OOIP.
Most fields follow some version of this “bell curve” production profile. In other words, production ramps up quickly when a field is first produced because underground pressures are high; natural geologic forces drive production.
But at some point, as pressures fall, production hits a plateau. This occurs long before all the OOIP is recovered. At this point, the producer can use certain techniques–such as oil and/or gas injection–to stabilize pressures and increase production. However, these factors are unlikely to do much more than simply stabilize production at relatively high levels.
My bottom line with this digression is that, even though Tupi may have OOIP of 30 billion barrels, current estimates are that it will see peak production of perhaps 1 million to 1.5 million barrels per day. That peak production rate would likely occur sometimes toward the end of the coming decade.
Of course, 1 million to 1.5 million barrels per day in the context of an 83-million-barrel-per-day market sounds less impressive than 30 billion barrels in reserves. But in many ways, it’s a more meaningful figure.
Once again, I don’t say this to belittle the Tupi discovery; it’s an extremely important and impressive find. However, it’s worth countering some of the sensationalist ramblings I’ve heard recently from the media about Tupi.
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Beyond Tupi
Buried amid the flurry of Tupi-related press releases are a few other points about Brazil’s deepwater production prospects. One is that, soon after announcing the Tupi discovery, Petrobras also announced the find of a huge gas field dubbed Jupiter. This field is also in the Santos Basin less than 40 kilometers from the Tupi discovery wells.Jupiter isn’t Brazil’s only gas field by any stretch of the imagination. In fact, natural gas is another major focus of Brazil’s deepwater exploration program. Just as with oil, Brazil has traditionally been reliant on imports to meet natural gas demand. See the chart “Brazil Gas Production and Consumption.”
Source: BP Statistical Review of World Energy 2007
But Petrobras has been bringing a series of new gas projects online over the past few years, just as with oil. And some major new developments are planned in 2008 and 2009. The largest of these deals is the Mexilhao field, due to come online in 2009. This single field is expected to produce 15 million cubic meters of gas per day, equivalent to 30 percent of total Brazilian supply.
All told, estimates suggest that Brazilian gas supply will expand from 28 million cubic meters per day in 2007 to more than 70 million cubic meters by 2010. And that doesn’t even account for the effects of newly discovered fields like Jupiter that weren’t included in Petrobras’ 2007 strategic review and outlook.
Brazil’s deepwater production growth potential for both oil and natural gas was impressive enough before the discovery of giant fields like Tupi and Jupiter in the Santos Basin. But Petrobras has additional large-scale exploration efforts underway in the Santos Basin; it’s quite possible the company will discover more significant fields that have the potential to generate production growth far above the estimates it published just a few short months ago.
In fact, current estimates are that Brazil could produce close to 4.5 million barrels per day in 2015, when comparatively Tupi was slated to produce roughly 3 million barrels per day in prior estimates.
And Brazil has certainly put the capital spending plans in place to fund an impressive exploration and development program. Consider that, in its strategic plan, Petrobras budgeted $112.4 billion in capital spending for the 2008-12 period. Of that total, Petrobras planned to spend some $11.6 billion on exploration and $53.5 billion on producing existing and newly discovered field development. The company also planned for another nearly $30 billion in spending on new refineries.
But, as noted above, this strategic plan was published before the Tupi and Jupiter finds. More recently, the company has said it plans to spend $12 billion by 2012 on further exploration in the Santos Basin, home to both Jupiter and Tupi, alone.
Consider that, in 2006, Petrobras announced plans to spend a total of $87.1 billion between 2007 and 2011. A year later, the firm boosted its four-year capital spending plans by close to 30 percent. That’s proof that Petrobras is willing to spend big on developing new fields and projects.
It’s also worth noting that Petrobras has locked a total of 30 deepwater and ultra-deepwater drilling rigs under contracts with major contract drilling firms. As I explained at some length in the Feb. 6 issue, Earnings on Tap, the global supply of deepwater rigs is extraordinarily tight right now. There simply aren’t enough rigs to meet demand for new project developments. Day-rates–the daily fee for hiring a rig–have risen to more than $600,000 per day for the most capable rigs, up from the $200,000 range earlier this decade.
In fact, Petrobras has locked in contracts on the largest number of deepwater and ultra-deepwater drilling rigs of any producer. The firms with the next largest contracted fleets, BP and Statoil, have 13 rigs each.
And Petrobras recently asked for quotes on three- to five-year contract deals on rigs starting in 2011. The company is keen to ensure that it has plenty of rigs to handle all its planned drilling and exploration projects.
If anything, Petrobras’ interest in securing rigs for after 2011 has picked up notably since the Tupi and Jupiter discoveries. The company has now been trying to secure ultra-deepwater rigs for 10-year contracts—a far longer-than-normal term—to produce these fields. This further suggests Petrobras is confident in the size and scale of these fields.
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How to Play It
Brazil is one of the few countries in the world that will generate significant oil and gas production growth in the coming years. And given its vast deepwater exploration and development efforts, Brazil is also one of the only countries that have the potential to see giant field discoveries in coming years along the size of Tupi. This makes Brazil an attractive destination for investors’ capital.One way to play the country’s energy growth potential is through Petrobras. Not only is the company involved in most of the current, upcoming oil and gas projects in Brazil, but it’s also widely regarded as the best-run NOC.
Petrobras was quick to book deepwater drilling rigs and has been willing to invest in its oil sector to fund future growth–both good signs that management thinks ahead. After all, many big producers who failed to book out rig capacity are now struggling to secure rigs to handle new their proposed projects.
As I noted above, Petrobras is just at the leading edge of a new production boom as it brings new deepwater projects on line gradually to 2012. Another catalyst for Petrobras’ stock is likely further announcements regarding Tupi, including an eventual plan and timetable outlining how the field is going to be developed.
As I highlighted in the most recent issue, production growth typically drives performance for E&P firms and the integrated oils. The same is true of Petrobras.
My only issue with Petrobras is valuation. Its shares have run up a great deal in the past year and a half, from under $40 in late 2006 to more than $120 earlier this year.
At this time, Petrobras looks expensive relative to the integrated oils like Chevron and Exxon; those two stocks currently trade at 9.4 times and 11.1 times, respectively, this year’s earnings estimates, while Petrobras trades at 14.5 times. On a price-to-cash-flow basis, the country trades at 9.8 times against 9.3 times for ExxonMobil and 7.4 times for Chevron.
Petrobras deserves to trade at a premium valuation because it has far higher production growth potential than most of the integrated oil companies. And as an NOC, Petrobras has greater access to reserves. I also don’t believe that any sort of political discount is warranted because Brazil’s regulatory climate in relation to the energy industry has been among the most stable in the world.
All that said, the current valuation premium looks steep. I’ve mentioned Petrobras before in TES and have long held it as a buy in the How They Rate Table. I’ll continue to track it there for now and may add it to the main portfolios on a pullback.
There’s no doubt that Petrobras is one of the world’s best-positioned producers and rates a buy for longer-term investors willing to ride out some fairly volatile swings from time to time.
Also note that the model portfolios already have exposure to the Tupi find through existing holding BG Group. BG Group is now a buy under 125.
But there are some other compelling plays on growth in Brazil’s deepwater sector. But Brazil is simply one facet of a global deepwater investment boom; offshore Africa, the Gulf of Mexico and Asia are three other markets experiencing significant growth in deepwater spending.
Longer term, the global services firms are one way to play the boom. Consider that Tupi is roughly 800 kilometers in length and 200 kilometers in width, according to Petrobras, and is in waters ranging from 2,000 to 3,000 meters deep. (That’s 6,500 to 10,000 feet.) This makes Tupi an ultra-deepwater field, which requires the most advanced rigs that are capable of drilling in the deepest waters.
But that’s only the beginning. The well Petrobras dug to produce Tupi had a total vertical length of 20,000 feet and drilled through a tough-to-drill mile-long layer of salt.
Pressures and temperatures in the well are also extreme. To produce such a well safely and effectively requires the use of the most advanced oilfield technologies; more complex field developments have higher services content. That means more work for the services firms–and more revenues.
In the Feb. 6 issue, I highlighted the services industry at some length. The only limitation on growth for some of my favorites in 2008 is a lack of deepwater rig availability. There aren’t enough deepwater rigs to meet demand, so activity isn’t accelerating as rapidly as it otherwise would. This is what many analysts have dubbed “the platform problem.”
This is the only reason I don’t currently recommend services giant Schlumberger. Next year, as new rigs go into service, the platform headwind will begin to abate. But for now, I prefer to focus elsewhere. For a full rundown of my rationale, check out that issue.
And for reasons I outlined in that issue as well, I continue to recommend Weatherford International. Although not traditionally seen as a deepwater services play, Weatherford has been performing more and more work in ultra-deepwater reservoirs, so it certainly has some exposure to this area.
A final play worth mentioning on the services front is deepwater seismic specialist CGG Veritas, a Wildcatters Portfolio holding. Seismic surveys are underground maps of rock formations used to identify promising targets for exploration.
Detailed seismic work is necessary even within existing fields to aid in well placement. After all, drilling wells in 10,000 feet of water that stretch to a total vertical length of 20,000 feet is hardly inexpensive. Producers want to make sure that their wells are placed to optimize production.
CGG Veritas has among the largest fleet of ships capable of performing such deepwater surveys. I highlighted the stock at more length in the Feb. 6 issue. CGG Veritas continues to rate a buy under 55.
Moving beyond these existing recommendations, I’m adding offshore engineering and construction (E&C) specialist Acergy (NSDQ: ACGY) to the Wildcatters Portfolio this issue.
This isn’t the first time I have written about Acergy. I dedicated the Dec. 5, 2007, issue to that industry and featured Acergy prominently.
The company specializes in subsea umbilicals, risers and flowlines, or SURF. SURF relates only to wells that are developed with subsea completions, meaning that the well is installed directly on the seafloor. This would apply primarily to deepwater developments.
It’s also important to note that SURF doesn’t just apply to new purpose-built projects. Acergy also handles subsea tieback deals, the hub-and-spoke construction projects that I noted above.
In other words, when Petrobras decides to hook a new series of deepwater wells to an existing FPSO, it needs SURF equipment installed to take production from the well–often for many miles via subsea pipeline–and then from the seafloor to the surface. Acergy installs all the pipelines, risers and unbilicals needed to connect new subsea wells to existing platforms.
Outside of SURF, Acergy also handles conventional work in the shallow water, performs maintenance and inspection work on subsea wells and pipelines, and even installs larger diameter subsea pipelines, known as trunklines, to transport hydrocarbons over longer distances. But SURF remains the key driver of results.
Acergy reported its fourth quarter earnings in Feb. 13, and overall trends in the SURF business remain rock solid. At the end of 2007, Acergy had a total backlog of unfinished projects topping $3.2 billion. This is a record backlog for the company and represents 24 percent growth over the backlog one year ago.
Better still, between the end of 2007 and the company’s conference call, Acergy noted that it’s added another $1 billion to its backlog.
The list of new projects adding to the backlog includes the giant Pazflor contract in Angola, one of the hottest deepwater markets in the world today. This award is for 46 subsea wells to be hooked up to a floating production system; the wells are found in waters up to 1,200 meters (4,000 feet) in depth.
Pazflor is being managed by European integrated oil giant Total. In addition to Pazflor, Acergy booked the Deep Panuke project in offshore Canada. That project is managed by Encana Corp and Shell’s Perdido deepwater project in the Gulf of Mexico.
In addition, Acergy completed a number of big deals in its most recent quarter, including the largest deal it’s ever undertaken: the Greater Plutonio deepwater project in Angola. Greater Plutonio is a $4 billion project BP manages that includes a series of 43 subsea wells tied back to a single floating production platform.
The wells, located in 1,200 to 1,500 feet of water, are considered deepwater wells. Just as with all its other big deepwater deals, Acergy handles the SURF installation for all these wells. The contract was worth $730 million and was awarded to Acergy and its competitor Technip, with Acergy taking the lead.
Based on the size and scope of all these awards, it’s clear that Acergy is a world leader in the SURF business. And by purchasing Acergy now, we’re getting in with an outstanding price. The company’s stock has been hit by two primary issues over the last six months: a poorly executed tax strategy and the Mexilhao Trunkline Project in Brazil.
The tax issue is a bit technical, and the specifics aren’t terribly important. Basically, the company’s tax rate soared to more than 43 percent in the fourth quarter well above the average tax rate for its peers in the 30 to 35 percent range. The problem arose from the way the company accounted for revenues and costs from some of its African contracts.
The end result was that Acergy ended up getting hit with an African withholding tax that it couldn’t recover. In addition, some of these projects were partly managed out of Acergy’s office in France, and the company also got hit by a significant tax bill from France, which has some of the highest tax rates in the world.
To combat this problem, Acergy hired a team of tax professionals who review each deal and how it’s accounted for so that this problem can be avoided in future. Management guided expectations for its full-year 2008 tax rate to just 35 percent, close to the peer group average. And there’s more room for further improvement.
The second problem relates to a trunkline deal serving the Mexilhao gas field in Brazil. A trunkline is nothing more than a subsea pipeline that connects a floating platform to the coast. In the case of Mexilhao, this was a $400 million deal to build a 120-kilometer long, 34-inch thick pipeline to transport treated gas from the Mexilhao platform to Caraguatatuba, south of Rio de Janeiro.
This contract turned into a total disaster. First, management admitted that trunklines are outside Acergy’s normal SURF core business. And second, the company tried to run the project as a joint venture between its North Sea office and its local office in Brazil. There was a delay in moving pipe-laying and other ships from the North Sea to Brazil.
To remedy the situation, Acergy was forced to negotiate with a single local contractor to perform some of the work. This was a case of a desperate client and a sole supplier; the cost was enormous. Acergy has taken some charges to reflect this problem, and the bad news from the deal is now out of the way.
In addition, Acergy has taken steps to mitigate the problem. First, the company removed most of the managers in charge of the project. Management also stated that there was a possibility it would receive a partial recovery of those inflated costs from Petrobras.
The tax and Mexihao issues are nothing new. Acergy has repeatedly explained the impacts of these missteps. That is why, even after missing estimates because of the tax problem, the stock actually rallied on the day of its report.
With these problems well-known and understood, they no longer have much of an impact on the stock. In addition, all E&C companies occasionally misstep on a single project; it’s just the nature of the business.
The good news about Acergy’s minor problems is that, if the company hadn’t faced these issues, it probably wouldn’t be trading at such an attractive valuation. Acergy trades at less than 15 times 2008 earnings estimates, less than its peer group average. That’s despite the fact that Acergy is heavily leveraged to one of the most exciting growth markets in energy: deepwater.
Over the next few years, you can expect to hear SURF awards for Petrobras’ projects, as well as for a series of new deepwater deals in Africa. Acergy stands well placed to win more than its fair share of these deals.
And its technology is absolutely crucial for deepwater developments. Acergy is added to the Wildcatters Portfolio as a buy under 24 and a stop at 15.20.
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Portfolio Updates
It’s been a busy few weeks for our portfolio picks. Several have either reported earnings or been the subject of market-moving news events. Here’s a brief rundown of some of the biggest stories.Wildcatter EOG Resources, highlighted at length in the most recent issue, announced a potentially large natural gas find in Canada. The find is located in northeastern British Columbia and could contain as much as 6 trillion cubic feet of gas reserves. EOG offered few specifics about how much production it can garner from the play.
In addition, EOG announced a significant boost to its oil and gas production estimates. The main drivers of that bump are the Barnett and Bakken shale plays. The lift to guidance is most impressive because it comes less than one month after EOG reported earnings and issued detailed guidance on production. This suggests there could be far more upside to production estimates as the year progresses.
EOG sailed nearly 20 percent higher on this release, though it’s since pulled back a bit. Needless to say, EOG Resources is now far above its buy target of 105, so subscribers without a position should steer clear for now. The stock has been highly volatile since releasing this bullish news. I’ll consider raising the target once the stock settles down.
We were stopped out of my recommended short position in the US Oil Fund (AMEX: USO) at $80 for a loss of around 12.5 percent. This position was intended as a hedge against potential weakness in energy prices because of fears of a US economic slowdown. I outlined my case for shorting the exchange traded fund at some length in the Jan. 23 issue.
Many of the rationales I outlined for shorting oil came to pass. Check out the chart “US Crude Oil Inventories” below.
Source: EIA
Over the past four weeks, US oil imports have averaged about 750,000 barrels per day higher than in the same four-week period one month ago. Meanwhile, inventories of crude oil in storage have risen from the extraordinarily depressed levels of late in 2007 to above average today. Therefore, the supply picture isn’t bullish.
Last year, supply and demand fundamentals drove the oil markets, but this year, the main factor driving crude is the dollar. The US dollar has fallen 4.3 percent so far this year, while oil has gained almost exactly 4.3 percent. Another way to look at it is that crude oil is actually trading up well under 1 percent in euro terms this year.
This isn’t a currency trading letter, but I wouldn’t be surprised to see the dollar bounce at some point this year as it becomes clear that Europe isn’t immune to the credit crunch, and its central monetary authority will inevitably follow the Federal Reserve and cut rates aggressively. When that happens, the short-term negative fundamentals for oil prices, noted in the Jan. 23 issue, will take the driver’s seat in the oil markets.
Until then, this hedge didn’t work, and I was wrong about oil. Take the loss in the US Oil Fund, and stand aside.
Fortunately, natural gas has vastly outperformed oil this year, rallying more than 20 percent compared to less than 5 percent for oil. This has been great news for our gas turnaround plays, such as land driller Nabors Industries. I highlighted my rationale for owning this stock in the Jan. 23 issue.
The company reported results in early February that were positive across the board, and the stock rallied on that release. There are two key points worth noting from the call.
First, Nabors’ international business is growing like a weed, and execution missteps that plagued the stock last year appear to be firmly behind it. In the fourth quarter, the company landed contracts on an additional 19 land rigs in international markets at high, attractive day-rates.
And as of the end of the quarter, Nabors was bidding on another 80 international deals. Given its experience overseas and strong sales force, I suspect Nabors will get more than its fair share of these deals.
International operations are set to grow by 50 percent this year and could grow by a similar amount in 2009. International earnings before interest and tax (EBIT) accounted for 31 percent of the total in the fourth quarter; in fourth quarter 2008, international EBIT will be around 45 percent of the business. Strength here is helping offset some weakness in North America, particularly Canada.
But there’s light at the end of the North American tunnel. Nabors says that rates for its more advanced rigs are stabilizing. This is probably due to continued strong drilling activity in unconventional gas plays; operators typically used more advanced rigs to drill these wells.
And given the uptick in gas prices, Nabors’ North American operations could surprise to the upside this year. I’m raising the buy target for Nabors Industries to 33.
Australian coal miner MacArthur Coal reported interim results and hosted a conference call last week and saw a significant rally to new highs as a result.
At first glance, the report looks terrible. The company’s profits are down 68 percent year-over-year, and its net income came in at the very low end of guidance. That guidance was issued back in November. And to top it all off, the company warned that it will be difficult to meet its production forecasts for this year.
But all of this is actually bullish for MacArthur. I’ve outlined the basic situation in the coal markets on a number of occasions, including the Jan. 2 issue, Taking Stock of 2007. MacArthur is suffering from the same basic problems as Australian producers: heavy rainfall in key producing areas, coupled with extreme port congestion.
MacArthur stated that 26.8 inches of rain, which flooded the mine and curtailed production, fell on its key mine in December and January. Meanwhile, the coal export ports designed to carry coal to markets in Asia are so overcrowded that miners are having trouble exporting the coal they produce.
The upside to all this is coal prices are soaring, and MacArthur will be able to lock in prices as high as $170 per ton on Asian coal export shipments. These new contracts last a year and go into effect on April 1.
That compares to the $67 to $68 per ton MacArthur received on average in 2007. Even with production problems, the company’s profits could triple this year.
The stock is now up 94 percent in US dollar terms from my original recommendation in early September and has been above its buy target for a few weeks now. I still see the potential for more upside in the coming months.
But given how extended the stock is near term, take profits on half your position in MacArthur Coal. In other words, if you own 100 shares, sell 50 of them and hold on to the remainder of the position.
Speaking Engagements
It’s time: Vegas, baby! Neil, Roger and I will head to the desert paradise May 12-15, 2008, for the Las Vegas Money Show at Mandalay Bay. Go to http://www.lasvegasmoneyshow.com or call 800-970-4355 with priority code 010671 to do the “what happens here stays here” thing.
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