Most of the big oil discoveries of the past decade have come from deepwater fields. As simple-to-produce onshore fields mature and their production declines, oil companies are continually pushing to produce more oil from complex offshore fields.
As the world’s final frontier of oil production, deepwater projects will command hundreds of billions in investment over the next decade. Investors who position themselves to benefit from that deluge of cash stand to enjoy tremendous gains. But to unlock those profits investors must understand the ins and outs of the Deepwater Golden Triangle, three prolific deepwater regions: Brazil, The US Gulf of Mexico and West Africa. In this issue, we’ll take a closer look at deepwater spending, the main legs of the Golden Triangle and two new plays on the theme.
In This Issue
As production from giant onshore fields and projects in shallow-water environments continues to decline, more and more of the oil we use will come from deepwater. See Going Deep.
Just follow your nose. Investments in deepwater projects will be concentrated in three regions, the Deepwater Golden Triangle. See Follow the Money.
Brazil’s pre-salt fields are the first leg of the Deepwater Golden Triangle, and national oil company Petrobras stands to benefit. See Brazil’s Pre-Salt Fields.
The deepwater Gulf of Mexico is one of the only oil-producing regions of the US that’s actually projected to grow production in the coming years. Here’s my take on how to play it. See Deepwater Gulf of Mexico.
A spate of current developments and new finds make West Africa the third leg of the Deepwater Golden Triangle. See West Africa.
Major oil producers are at the heart of developments in the Deepwater Golden Triangle, but equipment and services firms will also thrive. See Beyond the Producers.
Jan. 10, 1901, a group of drillers led by Pattillo Higgins and Captain Anthony Lucas struck oil just south of Beaumont, TX. The well, drilled in a geologic formation known as the Spindletop salt dome, was a true gusher; the initial strike sent a geyser of oil 150 feet into the air and took nine days to bring under control.
After the well was finally stabilized, it produced 100,000 barrels of oil per day, an unheard of production rate in modern times. The Spindletop well was so prolific it’s referred to as “The Gusher.”
The original Spindletop well was simple by modern standards, though relatively advanced in its day. But the true genius behind the well was the recognition that a salt dome–a giant underground geologic formation made of salt–could act as a trap for oil deposits. For modern geologists that’s a simple concept, but the seismic technologies that are commonplace today just didn’t exist in 1901. The discovery helped advance petroleum geologists’ understanding of which underground rock formations tend to hold oil, knowledge that ultimately led to the discovery of countless oilfields in the US and abroad.
Spindletop created one of America’s first true oil booms; the population of Beaumont more than tripled in three months, and Texas oilmen built great fortunes. Although production from Spindletop began to decline as early as 1902 and the area was no longer a key source of production by the late 1930s, it still boasts some of the nation’s most important refining and oil storage infrastructure.
Thanks to the wealth brought to the region by Spindletop and the petroleum industry, the rough triangular region around Beaumont, Port Arthur and Orange Texas came to be known as the “Golden Triangle.”
One of the core investment themes of this newsletter is “the end of easy oil,” an investment thesis I discussed at great length in the September 23 issue, Top Three Energy Themes. The basic concept is that vast prolific onshore oilfields such as Spindletop are history in most countries outside of the Organization of Petroleum Exporting Countries (OPEC). Although the US is still the world’s third-largest oil producer, production has been in decline since the early 1970s, dropping more than 40 percent since 1970. Even when the super-giant Prudhoe Bay oilfield on Alaska’s North Slope began production in 1977, total US production barely managed a blip to the upside.
Of course, there are still plenty of onshore fields under production in the US; some, such as California’s Los Angeles basin, have been under production for more than a century. But these are mature regions where wells produce a small fraction of what would have been commonplace three decades ago.
But that doesn’t mean there isn’t oil to be found and money to be made in non-OPEC countries. A string of deepwater discoveries in recent years has given rise to a new golden triangle, the “Deepwater Golden Triangle,” that’s already generating enormous wealth for investors.
Increasingly, the largest and most prolific oilfields discovered in non-OPEC countries are located in deepwater, roughly defined as any field found in waters more than 1,000-feet deep. The deepwater is truly the final frontier of non-OPEC oil exploration.
Deepwater projects are the quintessential example of what I mean by hard-to-produce oil, and the best proof that the end of easy oil is nigh. A recent example is BP’s (NYSE: BP) Tiber oilfield discovery in the US Gulf of Mexico. As I explained in the September 5 issue of Personal Finance Weekly, Giant Oilfield Spells Upside for Prices, the exploration well drilled in Tiber is among the most complex and expensive wells ever drilled anywhere in the world.
The field is located in waters more than 4,000 feet (1,220 meters) deep, and the total length of the well itself is more than 35,000 feet (10,685 meters)–more than 6.5 miles long from the bottom of the drilling rig to the bottom of the well.
The pressures and temperatures encountered at such depths tested the physical limits of drilling materials and technology. In fact, just a few years ago most producers and industry pundits felt drilling such a long well in deepwater was technically impossible.
BP hinted that Tiber will be bigger than another recent discovery made in the region, the Kaskida find. Kaskida is estimated at around 3 billion barrels, suggesting that Tiber could be one of the largest oilfields discovered anywhere in the world over the past two decades. Tiber could rival in size some of the major deepwater discoveries off the coast of Brazil.
But the knee-jerk reaction of many pundits is entirely incorrect. As I pointed out in the September 5 issue of Personal Finance Weekly and in prior issues of The Energy Strategist, most of the headlines announcing the discovery touted the potential size of the reserves. A popular lead was that Tiber contains reserves equal to an entire year of Saudi Arabian production. The implication is, of course, that Tiber and other oilfields like it mean more domestic oil supply, less dependence on OPEC and, therefore, lower crude oil prices.
But that’s complete rubbish. If you’re unfamiliar with the key difference between reserves, original oil in place (OOIP) and production, I suggest reading Giant Oilfield Spells Upside for Prices. The actual impact of Tiber is likely to be an incremental 200,000 barrels per day of oil production roughly a decade from now–hardly a drop in the proverbial bucket for a global oil market of around 85 million barrels per day. Tiber is a huge, impressive find for BP but won’t flood the market suddenly with a surfeit of supply.
The other key point about Tiber is that BP would never have bothered to drill such a complex well in such inhospitable conditions if it were able to produce more oil from vast onshore fields. The fact that deepwater projects are so popular right now indicates that there just aren’t many attractive alternatives for producers–companies are exploring the deepwater because that’s where the oil is.
As production from giant onshore fields and projects in shallow-water environments continues to decline, more and more of the oil we use will come from deepwater. Producing this oil is complex and requires the most advanced technologies available today. And producing such oil is also more expensive; to justify spending the billions required to develop these fields, producers will need higher oil prices.
Follow the Money
The Deepwater Golden Triangle connects three major regions for deepwater exploration and development: Brazil, the Gulf of Mexico (GOM) and West Africa. Tiber is just one small piece of the triangle.
The need to drill increasingly complex and expensive wells in the Deepwater Golden Triangle means that producers like BP will be pouring hundreds of billions of dollars into these three key regions over the next few years.
Oilfield consulting firm Douglas-Westwood published a deepwater market report earlier this year covering the period from 2009 to 2013. The firm expects deepwater spending to top $160 billion over this period, an average of around $32 billion each year.
Source: Oil & Gas Journal, Douglas-Westwood
This graph shows that deepwater expenditures rose from less than $20 billion in 2005 to close to $30 billion in 2008. Projections show a drop in 2009, primarily due to weak credit conditions and decisions by some operators to delay deepwater projects earlier in the year. However, spending is expected to pick up again into the coming decade and reach about $35 billion per year toward the end of the forecast period.
The study further broke down the spending by category and market. Check out the graph below for a closer look at where this deepwater spending is likely to occur.
Source: Oil & Gas Journal, Douglas-Westwood
Nearly 90 percent of this deepwater spending is destined for the Deepwater Golden Triangle. Africa is set to take the lion’s share of around $60 billion, followed by Brazil and Mexico with just under $30 billion each. Although that’s a lot of cash, these projections appear to be a bit conservative.
As I’ll explain in depth later in this issue, recent discoveries in the Deepwater Golden Triangle have prompted some producers to increase their capital spending budgets on deepwater plays after the Douglas-Westwood study came out. And comments from the major oilfield service companies and producers this year indicate that deepwater spending held up better in 2009 than most industry analysts expected at the beginning of the year. These developments suggest that the pronounced drop in 2009 spending, so visible in the above graph, was not as pronounced as expected.
Douglas-Westwood projected that producers will spend nearly $58 billion developing deepwater hubs to collect oil produced from fields located a great distance from the coast. Floating production platforms are expensive, so producers often build a single hub to collect production from multiple satellite fields. These fields are drilled, and a subsea control mechanism–known as a subsea tree–is placed on top of the well. Oil and gas can then flow to a hub via subsea pipelines.
The firm also expects companies to spend nearly $54 billion drilling wells and close to $40 billion constructing floating production platforms. All told, production over the next five years is likely to be close to 50 percent higher than over the past five years, a tremendous jump.
Whenever there’s a mound of cash that large heading for a particular market, investors should look for ways to profit. To understand the best opportunities in the Deepwater Golden Triangle, let’s examine each leg of the play in turn.
The first leg of the Deepwater Golden Triangle is Brazil and, in particular, a long list of deepwater discoveries in the Campos and Santos basins. I have written extensively about Brazil’s exciting deepwater discoveries in prior issues of this newsletter, including the March 5, 2008, installment, The Final Frontier. But producers have announced several additional discoveries since then and national oil company Petrobras has updated its internal projections; it’s high time for an update.
Source: BP Statistical review of World Energy 2009
This graph shows daily oil production in terms of barrels per day and doesn’t account for Brazil’s natural gas production on an equivalent basis. Brazil is currently the second-largest oil producer in South and Central America–despite its problems, Venezuela still has the edge. But there’s an important difference between Brazil and Venezuela: Brazil’s oil production is rising rapidly, whereas Venezuela’s output is on the decline. Over the past decade, Brazilian oil production has increased 90 percent, or roughly 900,000 barrels per day. Meanwhile, Venezuelan production has fallen more than a quarter, about 920,000 barrels per day.
This trend is expected to continue. Recent moves by the Venezuelan government to nationalize the oil industry and renegotiate contracts with foreign companies operating in the nation have resulted in the exodus of several key producers. To make matters worse, some of Venezuela’s most promising oil plays are relatively difficult and capital-intensive to produce; without help and capital from abroad, Venezuelan oil production will continue to fall.
The picture could not be more different in Brazil. Although some proposed new oil laws have made investors jittery in recent weeks, the fundamental impact of these new laws will be relatively benign. Several foreign companies are participating in the most promising recent deepwater finds announced over the past two years; Brazil has been among the best markets in terms of granting access to resources to foreign producers.
Brazil is unique among global producers in that the vast majority of the nation’s oil production comes from offshore fields. The national oil company (NOC) Petrobras (NYSE: PBR) accounts for more than 95 percent of Brazil’s production, and 88 percent of this output comes from offshore fields. The contribution of offshore fields to total production has risen steadily in recent years from just over 70 percent in the mid-1990s; offshore and, in particular, production from ultra-deepwater fields is expected to yield most of Brazil’s production growth in coming years. The following map shows the main oil-producing regions off Brazil’s coast.
Historically, the Campos Basin has accounted for most of Brazil’s offshore oil production. In 2008, for example, Petrobras produced more than 1.5 million barrels of oil per day there, nearly 90 percent of the company’s total output. But, thanks to several recent deepwater discoveries in the Santos Basin, production from that region is expected to ramp up and actually overtake the Campos Basin. The Santos Basin is located roughly off the coast of Rio de Janeiro, just south of the Campos Basin on the map above.
Many of the most promising plays recently discovered in the Campos and Santos Basin are deepwater pre-salt fields. Pre-salt oilfields are located deep under the seafloor, under a thick layer of salt; the extreme pressures and temperatures at these depths present myriad challenges to drillers. Penetrating the salt layers is notoriously difficult, and pressures encountered at those depths stress even the most advanced oilfield equipment. Managing temperatures can also be a big challenge, particularly as high-temperature oil moves through pipes that run through extremely cold, deep waters near the sea floor. Using he most cutting-edge technologies and techniques, however, producers are successfully drilling wells in pre-salt regions.
Here’s a rundown of some of the major deepwater oil and natural gas finds announced in recent years.
Tupi – Brazil has been drilling in the Tupi oilfield since 2006 and announced the discovery in late 2007 after its second successful well test. In mid-June of this year, Petrobras announced that the company had drilled a third well, dubbed 4-BRSA-711-RJS, encountering oil of a similar quality to the crude produced from the first two Tupi wells. The latest Tupi well was drilled in waters of more than 6,000 feet (2,000 meters).
Petrobras also used the occasion to reaffirm its prior reserve estimates for the Tupi oilfield of roughly 5 to 8 billion barrels of oil equivalent. Petrobras’ stake in Tupi is 65 percent. British producer BG Group (London: BG) holds a 25 percent stake, while Portuguese operator GALP Energia (Lisbon: GALP) controls the final 10 percent. BG Group has been somewhat more optimistic in its assessment of Tupi, stating that true reserves could be as high as 30 billion barrels of oil equivalent. But even if we assume the smaller estimates are closer to the mark, Tupi is undoubtedly one of the largest oilfields discovered anywhere in the world over the past two decades.
Petrobras is performing an extended test on the first two wells drilled in Tupi and is producing about 14,000 barrels of oil per day. Initial development of Tupi will involve a pilot project that uses a subsea pipeline to transport crude to the Brazilian coast; Petrobras expects this project to yield its first production at the end of 2010 and eventually generate about 100,000 barrels of oil per day. After collecting actual production data, Petrobras plans to expand its pilot project in 2013 until it achieves a “significant production level” in 2017. Some have estimated that at peak production levels–likely to come long after 2017–wells drilled in the Tupi oilfield could produce more than 1 million barrels of crude per day.
Iara – Petrobras announced the Iara discovery in September 2008, at the height of the financial crisis–needless to say, the find got a good deal less attention than Tupi. Iara is located on the same block as Tupi and has the same owners as its neighboring find. The initial discovery well was drilled in 7,000 feet of water to a total depth of more than 18,000 feet–far below the seafloor and through a layer of salt that can be more than a mile thick.
Petrobras estimates the total reserves at 3 to 4 billion barrels of oil equivalent. The company plans extended well tests for 2010 and 2011, followed by first large-scale commercial production in 2014.
Guara – The Guara field in the Santos Basin is located about 55 kilometers from the initial Tupi discovery well. The field is 45 percent owned and operated by Petrobras, 30 percent owned by BG Group and 25 percent owned by Spanish operator Repsol YPF (NYSE: REP). The discovery well was drilled mid-2008 in waters about 6,300 feet deep.
The NOC estimates total reserves of around 1 to 2 billion barrels of oil equivalent. Extended well tests are planned in 2010 and 2011, with full productions slated to take place after 2014.
Carioca – The Carioca field is located in water 6,300 feet deep and yielded both oil and significant quantities of natural gas when tested. Petrobras operates the field and has a 45 percent stake; BG and Repsol owning the remainder of the field.
I could continue to list additional fields, but the main point is that Petrobras has made some truly huge discoveries over the past three years and continues to conduct exploratory drilling on blocks throughout the Santos Basin. Thus far Petrobras has drilled 11 wells in the Santos Basin targeting pre-salt plays and has had a 100 percent success rate in finding hydrocarbons. The NOC has drilled a total of 30 wells in the deepwater pre-salt plays of the Campos and Santos basins with an 87 percent success rate in finding oil or gas. Those are truly staggering statistics.
In aggregate, Petrobras now plans to spend a total of $179.4 billion from 2009 through 2013. Roughly 60 percent of that amount will go to exploration and production (E&P), while 25 percent will go to downstream/refining operations. That works out to more than $104 billion to be invested in exploration and production in Brazil over the next few years, a major boon for oilfield services and equipment companies that specialize in the technology needed to produce these complex offshore fields.
This latest spending plan represents a $47.9 billion increase over the company’s previous figures; the majority of this money will fund new projects and field developments. And Petrobras’ long-term plan calls for spending more than $111 billion from 2009 to 2020 to develop its pre-salt plays.
The reward for all this spending and new field development: Brazil’s leg of the Deepwater Golden Triangle will generate some of the fastest oil production growth of any oil-producing region of the world out to 2020. The graph below provides a closer look.
This chart shows how much oil, natural gas and natural gas liquids (NGLs) Petrobras has produced since 2001 as well as the company’s forecast production through 2020. As you can see, Petrobras has grown total production roughly 5.6 percent annually since 2001. Management expects annualized growth to reach 8.8 percent through 2013 and 7.5 percent from 2013 to 2020.
If Brazil meets its goal of producing a total of 5.729 million barrels of oil per day, its oil production will be more than double current levels. To put this into perspective, consider that Petrobras projects it will produce more oil than giants Total (NYSE: TOT), Chevron (NYSE: CVX), Royal Dutch Shell (NYSE: RDS.A, RDS.B) and ConocoPhillips (NYSE: COP) by 2013.
Even more impressive, Petrobras meets its 2020 production targets it will eclipse ExxonMobil (NYSE: XOM), which currently produces around 4.25 million barrels of oil equivalent per day. Its total reserves would be between 25 and 30 billion barrels of oil equivalent, also well above Exxon’s reserve base. Given these statistics, it’s not hard to see why there’s so much excitement about Brazil’s deepwater oilfields and Petrobras.
Petrobras is also emerging as a leader in deepwater development, not just in Brazil but in other parts of the Deepwater Golden Triangle. Check out the graph below.
According to management’s estimates, Petrobras operates nearly one-quarter of the world’s total deepwater production. That’s 8 percentage points more than ExxonMobil. In addition to Brazil’s deepwater plays, the company owns stakes in deepwater wells in both Africa and the US Gulf of Mexico. Every well that Petrobras drills in the deep adds to its reputation and real world know-how, making it a valuable partner in deepwater projects all over the world.
Deepwater is perhaps the most direct play on the end of easy oil, and Petrobras is undoubtedly among the top operators in this area. The stock has run up amid a broader recovery for the Brazilian market and economy but remains inexpensive according to most metrics.
Petrobras A Shares (NYSE: PBR A) currently trade at 14.5 times forward earnings estimates, compared to 9.5 times earnings for Chevron and 11.5 times for ExxonMobil. But neither of the two American Super Oils boasts preferential access to Brazil’s deepwater plays nor the growth potential of Petrobras. Current estimates suggest that Petrobras can grow its earnings at close to 16 percent annualized over the next few years, whereas most major integrated oil companies are expected to grow annualized earnings between 5 and 7 percent. In light of these factors, Petrobras warrants its premium valuation.
Two versions of Petrobras trade on the New York Stock Exchange: Petrobras (NYSE: PBR) and Petrobras A (NYSE: PBR A). Both are entitled to the same earnings stream and dividends, but the “A” shares don’t lack the voting rights that accrue to “PBR” holders. The other difference is in price: The “A” shares trade at a discount to the straight “PBR” shares.
From my perspective, voting rights don’t warrant much of a discount, if any. After all, the Brazilian state controls Petrobras by virtue of its 55 percent stake in the company; votes from American holders of ADRs are a moot point. And the vast majority of US investors never actually vote or mail in proxies for companies they own even when they do have voting rights.
I am adding Petrobras A Shares (NYSE: PBR A) to the Wildcatters Portfolio as a Buy under USD46. Because Petrobras can be a volatile stock I am setting a loose stop-loss at USD28.50.
Be advised that different brokers have different systems for inputting the symbol for the A shares. Some may require you to type in the symbol as “PBR-A,” while others will show the symbol as “PBR_A.” If you’re looking to find a quote and basic trading data, Yahoo Finance uses the symbol “PBR-A.” If you cannot locate the A shares, I suggest calling your broker to determine how to enter the symbol in the system.
It’s also worth touching on recent proposed changes to Brazilian law governing the production of sub-salt fields; new oil laws have garnered some attention in the media, and proposals have been widely leaked. A few main points are worth keeping in mind.
New laws will not involve any changes to existing concessions. This is a big positive in my view, as it indicates that the Brazilian government isn’t going to change contracts unilaterally in the middle of the game. This should instill confidence in the regulatory environment governing foreign companies that operate in Brazil.
The National Energy Policy Council will designate pre-salt fields and some other plays as “strategic” and new terms will govern these fields. Specifically, Petrobras will be the only operator of strategic fields, and the government can decide if Petrobras will control 100 percent of the play or if the field will be up for public auction–in that event, Petrobras can have no less than a 30 percent interest. Once again, this deal would govern new deals not existing concessions; it might not come into play for another decade or more because Petrobras has its hands full with existing plays. That being said, there is one potential negative: An arm of the Brazilian government will have more latitude in determining the profit split between Petrobras and the government. This is a longer-term (i.e., at least 10 years into the future) concern but does bear watching.
The Brazilian government will be transferring some 5 billion barrels worth of oil production to Petrobras; the company would issue shares to cover the purchase price of these barrels. This is a complex deal but there doesn’t appear to be much volume risk for Petrobras: If the transferred fields do not generate as much oil as expected, the government would grant additional concessions to the company. Nevertheless, there are legitimate concerns about how much the government will charge Petrobras for this oil; the plan is to base the valuation on technical assessments by independent third parties selected jointly by Petrobras and the government. The devil is in the details, but given the chummy relationship between the government and Petrobras in the past, it’s unlikely the valuation will be too onerous for the NOC.
Brazil is a democracy with a legislature that doesn’t always see eye-to-eye with President Lula da Silva. Just as pending mid-term elections are an issue in the US health care debate, Brazil’s own 2010 elections loom large. At first the government planned to fast-track the new legislation through the Senate, but some senators sought to avoid hastily voting on laws that are of immense importance to the country’s future. Fast-tracking the proposal would have required a vote within 45 days, but it appears the government is backing away from that plan. That would push off a vote until early 2010. Since next year is an election year, the law might not be passed until late 2010 or 2011–if at all.
In short, Brazil’s proposed oil laws contain some carrots for Petrobras and some potential negatives; on balance, the legislation appears to be neutral to slightly positive. And bear in mind that the proposal is just a proposal–not law. The oil law proposals do not change my positive outlook for Petrobras.
This graph depicts deepwater production as a percentage of total US production. In 1990, deepwater production accounted for less than 0.2 percent of US output, a figure that grew quickly to 18 to 20 percent today. Over the next three to six years, that percentage is expected to explode to nearly one-third of total production because a number of deepwater fields discovered earlier this decade are due to come into production.
The Energy Information Administration (EIA) offers a litany of outstanding and timely statistics covering all aspects of the oil and natural gas industry, but sometimes their projections tend to be a bit too optimistic. For example, the agency expects an uptick in US onshore production over the next few years, whereas I expect onshore production to remain flat; new, unconventional fields such as the Bakken Shale simply offset declines from mature developments. In that conservative scenario, deepwater production will form an even larger percent of total US production.
According to the EIA, in 2007 the largest fields in the deepwater Gulf of Mexico ranked by total proven liquids reserves were Mars-Ursa, Thunder Horse and Atlantis. The first two of these fields are located in a region of the Gulf of Mexico known as the Mississippi Canyon, depicted on the map below.
As you might expect, the Mississippi Canyon is located near the Mississippi River, off the coast of Louisiana. Just to the west of the Mississippi Canyon you’ll see the Green Canyon, the region of the Gulf that’s home to Atlantis. This general area is outlined in yellow on the map above.
Mars-Ursa was one of the first deepwater fields discovered in the Gulf of Mexico. The field is located in water roughly 3,400 feet deep and first entered production in 1996. As of 2007 Mars Ursa produced a total of 75.2 million barrels of oil, equivalent to just over 200,000 barrels of oil per day. The field is operated by Royal Dutch Shell.
Thunder Horse is operated by BP, which controls a 75 percent stake, and co-owned by ExxonMobil. Discovered in 1999, the field was originally supposed to go online in the middle of this decade but faulty equipment and hurricane damage pushed that initial production to June 2008. (Deepwater projects are enormous, expensive multi-year deals and prone to delays). The field is located in water about 5,800 feet deep and can produce up to 250,000 barrels of oil per day along with significant volumes of natural gas; BP plans to add new wells that will allow it to maintain production near that maximum level for some time to come.
Atlantis is a BP-operated field that’s co-owned by Australian giant BHP Billiton (NYSE: BHP), which holds a 44 percent stake. Atlantis is located in depths ranging from less than 5,000 feet to as much as 7,000 feet. The field first entered production in 2007. The maximum output that the Atlantis production platform can handle is around 200,000 barrels of oil per day.
The deepwater fields currently under production in the Gulf of Mexico were discovered a decade or more ago and, in many cases, suffered significant delays between discovery and first oil production. Earlier in this issue I mentioned the enormous size and potential of BP’s recent discovery in the Tiber; back in 1999, the hype and excitement surrounding the Thunder Horse field was equally great. But it’s important to remember that like Thunder Horse, it will take many years for Tiber to enter production–don’t assume that deepwater fields discovered today will impact production volumes substantially over the next three to five years.
Tiber and Kaskida are situated in the Keathley Canyon, located to the west of the Atlantis, Thunder Horse and Mars-Ursa fields, off the coast of Texas. The map below provides closer look at the geographic position of these fields.
Kaskida is estimated to contain as much as 3 billion barrels of oil, and BP believes Tiber could be a larger play. Both fields are located in water that’s around 4,200 feet in depth. But the real technical challenge for these fields isn’t the depth of the water, but how far BP had to drill under the sea-floor and through thick salt layers: The wells drilled in Tiber are the longest anywhere in the world, though it’s possible that record will soon be broken.
BP is the field operator and has a 62 percent interest in the play. Petrobras has a 20 percent stake in Tiber.
One final play worth mentioning is Chevron’s Jack field, depicted on the map below.
The Jack and nearby St. Malo fields are in deeper water and further offshore than the Kaskida, Tiber and Thunder Horse Plays. For ease of comparison between the BP and Chevron maps, note the position of the Mad Dog field that’s visible in both pictures. Chevron’s test wells in Jack were drilled in water that’s around 7,000 feet deep and to a total depth of more than 20,000 feet. Although not quite as long as the wells in the Tiber play, these are still expensive and technically complex wells.
BP is the largest producer in the deepwater Gulf of Mexico and, thanks to recent discoveries and developments, is in a good position to maintain its lead. With total production of around 400,000 barrels per day in this area, BP currently accounts for about one-third of total oil production in the deepwater Gulf. That being said, BP is an integrated oil company, a group that tends to underperform during strong markets for energy; the only integrated oils I recommend outright at this time are Italy’s Eni (NYSE: E) and US-based Chevron (NYSE: CVX).
And although BP’s operations in the US GOM are excellent, it’s far from a pure play. For more direct plays on deepwater, the Golden Triangle and the US deepwater Gulf consider Anadarko Petroleum (NYSE: APC), a stock I added in the September 23 issue and Petrobras, a company I discussed earlier in this issue.
In the previous issue of The Energy Strategist, I examine a series of deepwater discoveries in the final leg of the Deepwater Golden Triangle, West Africa. I won’t repeat that analysis at length here; suffice it to say that there have been a number of recent discoveries off the coasts of Sierra Leone, Cote D’Ivoire, Liberia and Ghana. Check out the map below for a better look at this area.
My favorite play on deepwater finds in this region is Anadarko (NYSE: APC), a US independent producer that’s already announced a handful of oil finds in the region. Anadarko has significant acreage in these offshore areas and is conducting further exploration work; I expect announcements of further discoveries to act as an additional upside catalyst for the stock.
Although these new finds show promise, the water off the shores of Angola and Nigeria remains the center of West African deepwater production. Here’s a rundown of some of the major developments underway.
Kizomba – Kizomba is a large complex of offshore fields located off the coast of Angola in water that’s between 3,000 and 4,000 feet deep. The operator of the field is ExxonMobil, which holds a 40 percent stake. StatoilHydro (NYSE: STO), AGIP Petroleum, and BP also have stakes in the play, while the Angolan government collects fees as the concessionaire.
Most of the fields that make up Kizomba were discovered in the late 1990s; total recoverable reserves are estimated to be around 2 billion barrels of oil. Kizomba is being developed in a series of three stages: Kizomba A with a target production rate of 250,000 barrels per day, Kizomba B with another 250,000 barrels per day and Kizomba C with 200,000 barrels per day. The three stages have all entered initial production over the past four years.
Agbami – Agbami is Nigeria’s largest deepwater oilfield development, located just 70 miles off the coast in water that’s roughly 5,000 feet deep. Chevron operates the field, though both StatoilHydro and Petrobras have stakes in the play. The field recently started producing oil and is expected to ramp up to its full capacity of 250,000 barrels per day by year-end. Agbami is part of a series of projects that are generating production growth for Chevron, the one large integrated oil company that stands to grow output over the near term
Girassol – The Girassol field is located off the coast of Angola in waters that are about 4,500 feet deep. Total operates the field and holds a 40 percent stake. BP, Exxon, Statoil and Norsk Hydro also own stakes in the play. The field was discovered in 1996 and produced first oil in 2001–a fast development time for a deepwater project. Girassol produces roughly 250,000 barrels of oil per day.
All of the integrated oil names involved in these projects offer exposure to Africa’s deepwater finds, but none of them are pure plays. I prefer to buy Anadarko (NYSE: APC), as the incremental discoveries it’s making in offshore Africa will mean more to the bottom line and act as a greater catalyst for the stock.
The beneficiaries of growth in the Deepwater Golden Triangle go well beyond the producers I outlined above. In the previous issue of The Energy Strategist, I noted that one of the most leveraged plays on growth in deepwater spending are services and equipment firms that own the technology needed to produce these complex fields. The list includes: Schlumberger (NYSE: SLB), Weatherford International (NYSE: WFT), Dril-Quip (NYSE: DRQ), Noble International (NYSE: NE) and Seadrill (OTC: SDRLF). In this issue I am adding oil country tubular goods (OCTG) producer Tenaris (NYSE: TS) to the Gushers Portfolio.
OCTG are essentially pipes and casing that are used in the construction of wells. Casing for example, is a thick, large diameter pipe that’s cemented in place underground to prevent undesirable liquids, such as water, from seeping into a well and to prevent the well from collapsing.
Although manufacturing pipe might seem like a low-tech, low-margin business, that’s not the case. Drilling in deepwater environments exposes pipes and casing to extreme temperatures and pressures that can cause pipes to fail. Temperatures in a deepwater oilfield can exceed 300 degrees Fahrenheit (150 degrees Celsius) and pressures can top 10,000 pounds per square inch (psi); for comparison, normal atmospheric pressure on Earth at sea-level is just 14.7 psi. And in some cases corrosive compounds are found naturally occurring with oil and gas, chemicals that eat away at pipes over time.
Tenaris produces advanced, seamless OCTG. Traditional welded pipes are made from a sheet of metal that’s formed into a circular shape and then welded closed–an obvious stress point that will fail under extreme pressure. Seamless pipes made from advanced, super-strong metal alloys are needed to effectively drill and produce deepwater fields.
The global rig count–the number of rigs actively drilling for oil and natural gas–has fallen sharply over the past 14 months due to weak natural gas pricing and a pullback in oil prices late last year. Less drilling activity spells less demand for OCTG and, therefore, is bad news for Tenaris.
However, the company’s business has remained more resilient than one might expect; spending on deepwater and other complex international projects remained a lot more robust than expected amid the drilling downturn of late 2008 and early 2009. Deepwater projects call for Tenaris’ most advanced pipes and tubing, the company’s highest profit margin goods; even as total volumes of OCTG sold have declined, Tenaris has seen its mix of products sold shift toward the higher-margin, advanced OCTG used in deepwater projects.
I also see upside for Tenaris from a rebound in US (and international) natural gas prices. The US is a huge market for OCTG, as are the vast shale plays I discussed in the September 23 installment of The Energy Strategist. For reasons I outlined in that issue, I expect natural gas prices to rally into 2010, helping the rig count to recover from ultra-depressed levels. That should begin to stabilize demand for Tenaris’ less-advanced OCTG.
Buy Tenaris under USD40 with a stop loss order at USD25.