Oil And Gas
This year has certainly been a profitable one for the energy patch and The Energy Strategist Portfolios. As this is the final issue for 2006, it’s an opportune time to reflect and review some of our key calls and investing themes. In your next issue, to be published in early January, I’ll review the performance of all three Portfolios as of the end of the calendar year.
Although we’ve certainly made some money in traditional energy sectors related to oil and natural gas, the truly big gains this year have accrued to those willing to look beyond the ordinary. My favorite secular growth themes this year and into 2007 remain nuclear power and biofuels. Below I’ll review the basic themes and the latest news on my favorite plays.
And on the income front, master limited partnerships (MLPs) remain one of the most-overlooked and misunderstood asset classes in the market today; these partnerships also remain my top income idea for 2007 and beyond. Despite their stodgy image, MLPs have actually been a prime driver for portfolio returns in 2006.
Before I delve into today’s issue, a note to all new subscribers. In TES, I maintain three model Portfolios–Proven Reserves, Wildcatters and Gushers–each with a slightly different focus and strategy. The Proven Reserves Portfolio is really an income portfolio; the aim is high yield and relative stability. The Wildcatters Portfolio is my growth portfolio; my goal here is long-term capital appreciation.
Finally, there’s the Gushers Portfolio. This is really a trading/aggressive growth portfolio where I look for truly big gains and am willing to assume above-average risk. Subscribers should consider allocating money according to their risk tolerance and goals; the most-conservative investors may, for example, completely avoid the Gushers Portfolio and concentrate mainly on Proven Reserves. Those willing to take on more risk may, in contrast, allocate more capital to the Gushers plays.
In This Issue
Headlines have been declaring that warming effects of El Niño and an oversupply will be negative factors for natural gas this coming year. However, there are other factors to consider in this argument. See Weathering Gas.
Just as with natural gas, coal demand has also been impacted by the warmer temperatures. However, the coal industry is uniquely suited to handle such a demand decrease. See Coal Is King.
OPEC’s recent production cuts are not to be taken lightly. Given that the cartel would like to keep oil prices in the $55 to $60 range, I have some slightly different recommendations to maximize your gains in this industry. See Oil’s Well.
Because I tend to watch services and equipment companies focused on projects outside the US, I don’t see any of my recommendations in the Portfolios being significantly affected by energy prices. The seismic business is booming, and exploration activity is underway. See Services And Equipment.
Gains have been received in a variety of industries this year, but my three favorite secular themes remain nuclear energy, biofuels and MLPs. Here’s a rundown of how my recommendations in these fields have performed this year. See Secular Bull Market.
In this issue, I’m recommending or reiterating my recommendation on the following stocks:
I’m also recommending avoiding or shorting the following stocks:
Weathering Gas
I highlighted my basic outlook for the oil and gas markets at some length in the most-recent issue of The Energy Strategist, Looking for Some Upside. Since that time, there have been a series of unseasonably warm days all along the East Coast and Northeast. Because winter heating demand remains the prime driver of demand for gas, the warmer temperature has put pressure on natural gas prices and, to a lesser extent, crude oil prices.
That said, as I’ve pointed out before, I don’t regard the warm weather as a new revelation. The National Oceanographic and Atmospheric Association (NOAA) has been predicting that the presence of El Niño would result in a warmer-than-average winter this year since at least September. (I highlighted NOAA’s statement in the Oct. 18, 2006, issue of this newsletter.) This El Niño effect and the potential for another warm winter have been the subject of endless chatter and commentary among energy analysts and traders during the past three months.
A few points are worth noting, however. First, the actual text of NOAA’s winter weather prediction isn’t as bearish as some have argued. NOAA has predicted that the coming winter would be warmer than average but significantly colder than last year. Second, we actually saw some unseasonable cold snaps in October and November; the weather hasn’t been consistently warmer than average so far this season.
Further, warm spells could well continue to put pressure on energy prices. And for at least the next two months, energy futures traders will be keeping one eye on the thermometer.
But I continue to believe that we saw some important lows for both gas and oil in September and October. Remember, the warm winter scenario is no secret; the energy markets have largely priced in the potential for a warm winter. Well-known facts such as this rarely lead to profitable investments.
In addition, demand is only half the equation. There’s also the issue of supply. The simple fact is that natural gas inventories in the US remain above average for this time of year; this inventory hangover is a result of the record warm winter of 2005-06.
However, the inventory overhang in the US isn’t as large as it was six months ago. Despite the headlines, inventories have actually normalized a great deal since that time. And check out the chart below.
Source: US Energy Information Administration, Bloomberg
This chart depicts the weekly injection/withdrawal gas statistics. Injection refers to the addition of natural gas into US storage facilities; on the chart, gas is being injected into storage when the lines are in positive territory. Gas withdrawal refers to removing gas from storage (for use); this occurs when the lines are below zero.
I examined the past five years of weekly gas injection/withdrawal statistics for the US market. I plotted the largest figures, the lowest figures, the average and, of course, 2006 data on this chart. In calculating the average and high and low figures, I didn’t include this year’s data.
A few points here are worth noting. First, for roughly the first half of 2006, the US saw either lower-than-average withdrawals or higher-then-average injections. You’ll note that the light-blue line (representing this year’s data) tended to be significantly above the dark-blue, five-year average line up through roughly midyear. This was mainly because the 2005-06 winter was very warm and the spring was benign; demand for gas remained muted from January through June of 2006.
But there’s a notable shift after the first half of the year. Note in particular that we actually saw some gas withdrawals during the summer months. You can clearly see that this hasn’t occurred in any year in the past five years except for 2006.
This dip was the result of the extraordinarily hot summer weather experienced across much of the country in the summer of 2006. That weather resulted in record electricity demand. Because gas is an important source of electricity, the surge in demand actually resulted in a highly unusual midsummer gas withdrawal.
A casual glance at this chart also shows that, for the most part, the US withdrawal/injection line has been roughly at or below average since midyear. In other words, for most of late summer and early fall, gas injections were lower than normal. Moreover, since early fall, gas withdrawals have been higher than average.
Note that this chart doesn’t include the data for the very warm days in mid-December; data covering this period will be released later this week. I have no doubt that the past week has brought withdrawals of gas that are lower than average for this time of year. It’s even possible we’ll see net injections of gas during the past week. However, this hasn’t been the case for most of the fall months.
Bottom line: There are still plenty of gas bears citing excessive inventories as rationale for a drop in gas prices this winter. But the actual statistics suggest that gas inventories are gradually normalizing.
Then, of course, there’s Canada. As I pointed out last week, drilling activity in Canada has been weaker than average during the past few months.
Canada, unlike the US, has actually seen a year-over-year decline in drilling activity. Given the high well decline rates in Canada, this is surely impacting Canadian gas production. Perhaps that’s one reason why the Canadian gas inventory picture looks so much different from that of the US.
Source: Bloomberg
This chart shows actual gas in storage, not withdrawals and injections. Note that until early fall, Canadian natural gas inventories were running well above average and well above levels witnessed in the past three years. That’s because Canada, like the US, experienced a warmer-than-average winter last year.
But more recent, that picture has reversed. Canadian gas inventories have been running close to average levels and actually under average levels for much of the period in question. I suspect that the decline in Canadian drilling activity is already resulting in an impact on inventories despite warmer-than-average temperatures.
And if you’re wondering why Canadian gas inventories are important for the US market, consider that Canada is the US’s single-largest source of imported natural gas. A decline in the Canadian rig count will ultimately result in lower imports of gas and shrinking US inventories.
All these points reference only the US market. Europe is also a major market for natural gas; Europe is even more dependent on imported gas than the US is. And Europe relies heavily on natural gas supplies from Russia to meet domestic demand.
Russia has been in the news a great deal recently, and not all the reports have been the latest twist in the cloak-and-dagger Alexander Litvinenko poisoning scandal.
Specifically, some prominent pundits are arguing that by the end of this decade Russia won’t have enough natural gas to both meet domestic demand and honor all of its European export contracts. The increased urgency of Russia’s efforts to end subsidized pricing to former Soviet states suggests that there’s at least a kernel of truth to that argument.
I highlighted this Russian gas story at some length in the Oct. 5, 2006, issue of TES, Review And Preview. But it’s worth reviewing it here.
Gazprom is unique in that it’s Russia’s dominant gas producer and, therefore, has privileged access to the world’s largest gas reserves. The Russian government treats the firm somewhat like a national champion.
The firm currently makes most of its money by exporting gas to Western Europe. The prices it receives in Europe are based on a formula that ties the price of gas to the price of crude oil with somewhat of a time lag.
But in Russia’s domestic market and in other former Soviet-controlled states, Gazprom isn’t allowed to charge full world prices. Instead, the firm sells gas at subsidized rates that can be 20 percent or less the price Western Europe pays. Gazprom, needless to say, doesn’t make much money in these markets.
The problem is that subsidies create price distortions and undesirable behavior. Because the price of gas is so low in these domestic and regional markets, consumers use more gas than they otherwise would.
Booming demand in these “low-price” markets means less gas is available for Gazprom to export to “high-price” countries like Western Europe or even the US. With the Russian economy growing robustly the past few years, demand for gas has been growing at a particularly quick pace.
Just last week, Russia threatened to cut off natural gas supplies to both Belarus and Georgia if these countries failed to agree to pay far-higher gas prices next year. A year ago, Russia actually cut gas supplies to the Ukraine briefly as a negotiating chip to prompt the country to accept higher prices. The strategy worked to an extent, but Italy and parts of Germany nearly ran out of natural gas during the peak of the winter heating season as a result of the cuts.
Belarus has been politically friendlier toward Moscow than Georgia or the Ukraine. The nation has been paying $47 per thousand cubic meters for its natural gas supply against prices of $250 to $300 in Western Europe.
Now, Moscow wants to hike Belarus prices to $200. This is a dramatic price increase for a country that’s been seen as a political ally. Russia wants to more or less end all subsidies to former Soviet states by 2008; I suspect that there will also be a gradual push to end subsidies within Russia to domestic consumers as well.
I see two points worth noting about all this. One is that the gas supply situation outside the US remains tight.
The second is that a normalization of subsidized gas prices to more-competitive levels is good news for Gazprom. I’ve been eyeing this company as a potential portfolio addition; as the chart below shows, the stock has been trading sideways for some time now.
Source: Bloomberg
To make a long story short, I recognize the importance of weather to the short-term picture. However, I’m not convinced by the simplistic arguments about El Niño and massive gas oversupply.
Although I’m certain we’ll see more volatility in the next two weeks, I remain comfortable holding gas-focused exploration & production (E&P) firms EOG Resources, BG Group and XTO Energy. I outlined my case for owning these companies in the most-recent issue of TES, Looking For Some Upside.
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Coal Is King
Coal prices and coal stocks have been somewhat leveraged to natural gas prices recently. This stands to reason as coal is the most-important fuel for electric power plants in the US.
The winter heating season marks a period of heavy coal demand just as it’s a time of peak natural gas usage. Therefore, the recent warm weather has also reduced coal demand.
Coal spot prices have certainly declined since the spring. But that decline lost steam this fall; prices for all types of spot coal have been more or less flat the past few months.
And remember that coal-mining firms aren’t totally tied to the price of the commodity itself. Most of the coal miners sell their production as part of long-term contracts; big, reliable producers can often sign these contracts at a significant price premium to the widely quoted “spot” rate.
In addition, although coal prices are now lower than they were in May, they’re significantly higher than spot prices two to three years ago.
Coal mining firms are constantly rolling over their long-term contracts. In other words, when an old supply contract expires, coal-mining firms will go out and reprice that production on a new multi-year deal. Therefore, some of the contracts still being honored today were priced back in 2000-03, when coal prices were far lower than right now.
For example, the management at Arch Coal provided some nice statistics in its late-October conference call. The company stated that it’s been signing contracts for 2007 coal deliveries from the Powder River Basin (PRB) at prices 25 percent higher than its average realized coal price in the third quarter of this year.
For coal contracts covering its highest-value Western coals, Arch is signing contracts prices for delivery as far out as 2010, some 50 percent above its current realized prices. Therefore, as companies roll over these low-priced legacy contracts to more market-based rates, earnings will continue to benefit.
On the supply front, costs to mine in the Appalachian coal region continue to rise, rendering many operators in the region unprofitable. Supply from Central Appalachia is likely to continue falling; softer supply growth will also put a floor under prices.
The real growth in production will come from the Western US PRB. Mining costs in the PRB are also rising but at a far-more-muted pace than in the East.
Bottom line: Shifts in sentiment surrounding the weather will continue to affect Wildcatters recommendation Peabody Energy. Nonetheless, the intermediate- to longer-term bullish case is intact; I continue to rate Peabody a buy.
For more specific analysis of this stock, check out the November 1 issue of TES, Earnings Bonanza.
For the record, all miners focused on Appalachian mining–including Alpha Natural Resources, James River Coal Co, Massey Energy and International Coal Group–should be avoided. These companies don’t have the potential to grow production as quickly as Peabody, and costs in Central Appalachia are rising rapidly; profit margins have been severely squeezed in the East.
I’ve been recommending avoidance of all these names since the end of 2005, and my outlook is unchanged.
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Oil’s Well
Winter weather does have an impact on oil prices. In some parts of the country, notably the Northeast, heating oil is still widely used. Demand for heating oil tends to ramp up during the winter months, just like demand for natural gas. The summer driving season is a more-important period for oil consumption, but heating demand is relevant.
Warm winter weather has cooled demand for heating oil. Interesting, however, warm weather has also encouraged traveling and gasoline demand has been higher than normal for this time of year. The US oil gasoline demand picture still looks robust near term.
Far more interesting is what’s been happening on the supply front recently. The Organization of Petroleum Exporting Countries (OPEC) agreed to reduce output by 1.2 million barrels per day on November 1.
Many pundits chose to ignore that cut, saying that OPEC was simply trying to talk up oil prices and there would be no real action. As I stated on multiple occasions, I disagree with that view.
The reason is simple: A weak tanker market suggests reduced demand for oil transport from the Persian Gulf. (I highlighted this phenomenon at some length in a November 30 Flash Alert, Tankers, Airlines, Oil And Gas.) Check out the Baltic Dirty Index chart of tanker rates below.
Source: Bloomberg
This chart shows tanker rates over the past four years normalized to fit on one chart. Typically, tanker rates surge from the August-September months straight through the end of the year.
But this year has been different. Tanker rates continued to slide lower in the late summer and early fall, bucking the seasonal uptrend. And although rates have jumped higher this month, 2006 tanker rates are lower than in any other year covered by this chart.
The worst of the weakness seems to be in the very large crude carrier (VLCC) market. These are the primary tankers used to haul oil from the Middle East to the US and Asia.
Tanker rates typically rise when the Middle East is shipping a good deal of oil. This very weak fourth quarter picture suggests that the OPEC supply cuts may be more than meaningless rhetoric. At any rate, there’s been a meaningful decline in oil shipped by tankers lately. Ultimately, this will filter though in the form of lower domestic supply.
At OPEC’s December 14 meeting, the organization agreed to another 500,000-barrels-per-day cut in output to take effect February 1. Check out the text of the statement following that meeting:
OPEC remains vigilant about the potential for non-OPEC oil production to grow next year. The organization appears more than willing to discuss further supply cuts in an effort to keep oil prices above the $55 to $60 per barrel level.
These points all support my view that oil prices will remain well supported in the $55 to $60 region. The only real risk I see to crude is a major global recession in the latter part of 2007; it’s too early to start forecasting such a slowdown.
Nonetheless, the prospect of further OPEC supply cuts isn’t good news for the tanker firms. Already, the lower-than-normal fourth quarter tanker rates are likely to result in some downside surprises to earnings.
In the Proven Reserves Portfolio, I currently recommend General Maritime as part of what’s known as a pair trade. I recommend shorting another tanker firm–OMI–to hedge the potential for downside in GenMar.
Because GenMar offers dividends well in excess of OMI, this pair trade allows us to capture GenMar’s dividends while protecting our position against a general decline in the tanker sector. The short in OMI should help guard against declines.
Also, because Genmar focuses more on the Atlantic basin tanker market and smaller tanker ships, it’s less exposed to OPEC supply cuts than firms with concentrated exposure to the VLCC market. This is precisely why I recommended selling out of Frontline in the November 30 Flash Alert. Frontline had previously been a trade in my aggressive Gushers Portfolio.
Frontline is still the best of breed in the VLCC tanker space. If you wish to continue holding Frontline as a long-term income play, I recommend shorting Overseas Shipholding Group (NYSE: OSG), another VLCC-focused tanker company, as a hedge against your Frontline holdings.
If the tankers all keep falling, gains in your Overseas Shipholding short should offset losses in Frontline. Overseas Shipholding pays only a meager dividend yield compared to Frontline’s giant payout.
When you are short a stock, you must pay dividends in lieu of the company. That makes shorting Frontline for any length of time impractical; the company’s dividends are just too high. But Overseas Shipholding has consistently followed a low dividend policy.
Given the recent weakness in tanker shipping rates and the prospect for more OPEC cuts, Overseas Shipholding is now a short recommendation in the Gushers Portfolio.
Just to clarify my position, I continue to recommend General Maritime as a buy using OMI as a short hedge. I’m now also recommending a short in Overseas Shipholding; the company is uniquely leveraged to this year’s unusually weak tanker market. I see downside in Overseas Shipholding to under $50 by the first quarter of 2007.
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Services And Equipment
There’s been some knee-jerk selling in most of the services and equipment firms related to the warm weather. That said, I don’t believe that the services and equipment companies recommended in TES will have much actual earnings downside, even if a warmer-than-normal winter this year were to result in further downside to US gas prices.
This is because I recommend avoiding services and equipment firms that are overly leveraged to the US and Canadian markets. North America is far and away the most-volatile drilling market; projects tend to be small scale and short-term. That means that, as we’ve witnessed in Canada this year, drilling activity can be quite sensitive to commodity prices.
In contrast, international projects tend to be longer-term, major projects. Even a relatively large decline in oil and gas prices wouldn’t have a huge effect on activity.
In the most-recent issue of TES, I offered my bullish case for owning Tenaris, the largest global manufacturer of oil country tubular goods (OCTG). The stock is up some 35 percent since my original recommendation and is up considerably just since my last mention on December 6, partly as a result of some unconfirmed rumors that Gazprom may try to acquire Tenaris.
Although I continue to like the company fundamentally, these rumors have pushed the stock above my buy-under target. I’d only look to enter Tenaris on a dip toward my recommended target of 48.
In addition, I’m raising my recommended stops to lock in gains. For those subscribers willing and able to trade options, I recommend an options strategy for locking in gains on Tenaris while leaving room for plenty of upside. The strategy will be detailed in a flash alert I’ll be sending out in the next two weeks.
I outlined my rationale for recommending Petroleum Geo Services in the November 1 issue of TES. As this company’s main business is seismic surveys outside the US market, I don’t see that it has much real downside no matter what happens to US gas prices.
Recall that seismic surveys involve using sound waves to generate a sort of map of underground rock formations and potential petroleum reservoirs. Seismic surveys are a key feature of any exploration activity. As oil and gas prices remain high by historical standards, producing firms have stepped up their exploration activity of late.
Bottom line: The seisimic business is booming, and Petroleum Geo Services remains in the sweet spot of that trend. I’m maintaining my buy rating on Petroleum Geo; note the raised stop recommendation.
I highlighted both Dresser-Rand and Schlumberger in the December 6 and November 22 issues of TES, respectively. I won’t repeat my arguments here. Both Dresser and Schlumberger remain buy recommendations.
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Secular Bull Markets
Oil, gas, services and coal stocks have certainly handed us some nice gains in recent months. But by far the biggest percentage gains have come from my three favorite secular themes: nuclear energy, biofuels and MLPs.
These remain my favorite themes for 2007–all should continue to perform well regardless of the action in oil and gas prices. It’s worth offering a brief recap and review of each theme in turn.
Nuclear Power
I offered a detailed and comprehensive look at the nuclear industry in the July 26, 2006, issue of TES, The Nuclear Option. I recommend that all new subscribers to the newsletter and all investors unfamiliar with nuclear power and the uranium market review that issue, which is available in the archives.
In brief, nuclear energy is a clean, cheap and reliable source of power. The demand for electricity is actually growing faster than the demand for transportation fuel in most developed and developing markets. Countries like China and India are seeing demand for electricity grow particularly quickly–at many times, the rate of US demand growth.
Although North American consumption of power is projected to double between 1990 and 2030, non-Organisation for Economic Co-operation and Development (OECD) countries should see demand rise by close to a factor of five over the same time period. Meanwhile, Indian power demand is set to rise by a factor of seven; Chinese demand is expected to increase by more than 10 times.
These trends in the developing world should come as little surprise. The simple fact is that, as nations develop and become wealthier, demand for electricity accelerates.
Consumers in China are starting to buy the same types of household appliances, such as air conditioners and refrigerators, as their counterparts in the Western world. The changes are coming at a rapid pace. According to the Chinese government, more than 80 percent of Chinese urban households have air conditioning, up from around 30 percent just five years ago.
All of these basic consumer appliances require electricity, powering a massive increase in demand. Demand has risen so rapidly, in fact, that Chinese power generators are having considerable difficulty keeping pace; there have been reports of widespread power blackouts in China during the past few years.
And, as is the case in the US, demand for electricity worldwide is growing faster than demand for oil. For example, according to the Energy Information Administration, Chinese oil demand will grow approximately 3.8 percent annually between 2003 and 2030. Meanwhile, electricity demand over the same period is set to grow at 4.8 percent annualized, a full percentage point faster.
Although China and India could rely on coal to meet this demand, that’s not an attractive option. Heavy reliance on less-efficient coal plants is taking a toll: Of the 10 most-polluted cities in the world, seven are located in China. It’s estimated that acid rain falls on more than a third of the country, causing damage to crops.
Smog and respiratory illness are also more common in China than in most of the developed world. In fact, in some cities, the smog and soot are so thick that cars typically drive with their headlights on during daylight hours.
Although gas is a cleaner option than coal, most countries with rapidly growing demand just don’t have enough gas production domestically to meet their needs. That means importing natural gas from abroad in the form of liquefied natural gas (LNG).
LNG imported from places such as Russia and the Middle East carries significant supply risk and, most likely, a fair degree of political risk. In addition, more than 70 percent of the cost of generating power in gas-fired plants is the cost of the gas itself; with gas prices at current levels, it’s an expensive source of power.
A Finnish government study conducted in 2000 examined the change in electricity costs for coal, nuclear and gas-fired plants. The study concluded that a doubling in uranium prices would result in a 9 percent jump in the cost of nuclear-generated power.
But a doubling in coal and natural gas costs would cause a 31 percent and 66 percent rise in electricity costs, respectively. Even the rapid rise in uranium prices in recent years has done little to change the economics of nuclear power production.
The key fuel for nuclear power plants is uranium. Bottom line: There’s a supply squeeze of epic proportions underway in the uranium market; uranium remains perhaps the tightest commodity market on Earth right now.
Consider that, in 2005, the world consumed roughly 175 million pounds of uranium, while total mine production was just 110 million pounds. That 65 million pound deficit was covered by a combination of reprocessed nuclear warheads and inventories of uranium owned by utilities and the government. But inventories are now running low, and the deal with Russia to reprocess nuclear warheads into plant fuel is set to end soon.
To make matters worse, as I highlighted in an October 26 Flash Alert, the world’s largest supplier of uranium, Cameco, experienced a major flooding problem at its Cigar Lake mine in Canada. Originally, Cameco had planned production from Cigar Lake beginning in 2008; this flood will delay production for at least one year.
Although a one-year delay at a single mine may not seem like a big deal, keep in mind that this single mine was set to produce about 10 percent of global uranium demand within a few years of opening. Therefore, the loss of the Cigar Lake production is the rough equivalent of taking Saudi Arabia out of the world oil market.
Consider that in late July uranium oxide (yellowcake) was trading around $47 per pound; lately, uranium has surged to more than $70 per pound. And at the beginning of 2006, uranium was trading in the mid-30s per pound. In fact, uranium prices haven’t declined week over week since 2003.
With the current supply of mined uranium falling well short of demand, utilities have been running down their inventories of uranium to meet needs. For the most part, utilities built up their inventories during the low price environment of the 1980s and ’90s; with inventories disappearing, utilities need to contract new supply.
And that doesn’t even count the added demand that will come from all the new nuclear plants scheduled for construction in the next decade-and-a-half.
This is only a brief overview and review of the uranium story. Suffice it to say that I believe the uranium bull market remains in its early stages.
There will be corrections along the way, but I’m looking for the spot price of uranium oxide to exceed $100 per pound by the end of this decade. Increasingly, this $100 target is looking conservative; I see the risks to the upside. For a more complete treatment, please check out the July 26 issue of TES.
I recommend two primary ways to play uranium: Cameco and what I call my uranium field bet. As noted above, Cameco is the world’s largest uranium producer. The company produces more than 21 million pounds of uranium oxide (U-308) annually; that’s nearly a fifth of total global production in 2005.
In addition, Cameco sits atop some of the world’s richest mines and has some excellent projects (including Cigar Lake) that will likely begin production in the next three to five years. In many ways, Cameco is the ExxonMobil (NYSE: XOM) of uranium, only far more dominant and important to its market.
Cameco is up more than 100 percent from my original recommendation in 2005 but hasn’t performed particularly well lately; we’re up just 7 percent since midyear. There are two main reasons for that. The first is the considerable uncertainty surrounding the company’s Cigar Lake project; it will likely be two months or more before we get a better picture of exactly how long this project will be delayed.
Second, and more important, Cameco suffers from legacy contracts. Just as with the coal mining firms, this company does very little trading on the illiquid uranium spot market. Instead, it contracts with utilities to supply uranium over long-term contracts–sometimes five years or more in duration.
Five years ago, with uranium trading under $10 per pound, a long-term supply contract signed in the low to mid-teens per pound would have been considered a real coup for Cameco. The company always did pride itself on obtaining premium pricing; the company, despite recent production issues, remains one of the world’s most-reliable suppliers.
But with uranium now in the mid-60s, those contracts signed five year ago look hopelessly anachronistic. It will take years for Cameco to work through all its legacy contracts; as these contracts are rolled over, the company’s realized uranium sale price will gradually rise.
But for now, the average price the company receives for its uranium is far under the current spot price. This is an elaborate way of saying that Cameco has only limited upside leverage to uranium price increases.
As a result, I’m cutting Cameco to a hold recommendation in this issue; I recommend new subscribers steer clear of the stock.
My second way of playing uranium is the uranium field bet. I recommend that subscribers concentrate their uranium investments on this play right now.
The concept of the uranium field bet is quite simple: Unlike Cameco, some smaller so-called “junior” uranium companies don’t have many legacy contracts to contend with. In many cases, these juniors are only just starting production or are still years away from production. Therefore, they have more upside leverage to uranium prices than Cameco itself.
That said, juniors also carry far higher risks. Uranium mining is a risky business. Production delays, unforeseen project cost and simple labor and raw materials inflation can all have important effects on the economics of a particular mining project. And production costs vary wildly depending on the grade of ore mined and how large overall reserves are.
Riskier still is exploration. Uranium explorers buy acreage and drill holes, taking core samples to evaluate reserve size and ore grades. Sometimes, even the most-promising reserves just don’t pan out and can never reach economic production. It’s impossible to know this for sure until you’ve spent considerable sums on exploration; only when uranium is produced can we really know for sure the full costs and viability of a project.
For the best chance at big returns, I recommend casting a wide net: Instead of just buying one or two high-risk names, I recommend placing a smaller amount in five to 10 such companies. I call this the uranium field bet.
Below is a table outlining my current uranium field bet selections. The returns listed in the table are the returns since I first recommended the stocks in the newsletter.
Source: Bloomberg, The Energy Strategist
For my rationale for owning these stocks, review the July 26 issue. Here’s a brief rundown of recent news on my uranium field bet picks:
Paladin Resources (Australia: PDN; Toronto: PDN)
Paladin is an Australian company with dual listing under the symbol PDN in both Australia and Canada; I’ve offered the Canadian symbol because it’s easier for most US investors to buy. Paladin has one of the most-advanced slates of uranium projects of any company anywhere in the world.
Paladin’s Langer Heinrich uranium project in Namibia was commissioned in September and began producing ore. The final construction on the project is scheduled for December 2006 with the first uranium sales from the mine slated for the first quarter of 2007.
The mine should hit its initial target of 2.6 million annualized pounds of U-308 by the third quarter of 2007. When you consider just how supply-constrained the global uranium market is, 2.6 million pounds is a considerable quantity. Moreover, Paladin is one of the only producers anywhere in the world that will bring new production online this year.
In addition to Langer Heinrich, Paladin has development projects in Africa and Australia that are ongoing. These could well result in further production in the next two to five years. Paladin remains one of my favorite uranium plays.
SXR Uranium One (Toronto: SXR)
SXR is like Paladin–an actual emerging producer. The company’s Dominion Uranium project in South Africa is scheduled to begin production in the first quarter of 2007; SXR announced a contract to sell 1.5 million pounds of uranium from the mine between 2008 and 2012. The contract is with an unspecified “western” utility company.
Better still, the contract wasn’t signed at a fixed price; the sales price for this uranium will be based on prevailing spot prices at the time of delivery. There’s even an escalating price floor for uranium prices under the contract. This is another clear sign of the pricing power emerging producers like SXR and Paladin have over their customers.
The Dominion project should begin production at the rate of 2 million pounds annually in 2007. There’s potential to further boost production to around 4 million pounds annually by 2011.
SXR also has a mining lease on the Honeymoon uranium project in South Australia. Actual production is scheduled for 2008 and will total roughly 900,000 pounds annually.
Energy Metals (Toronto: EMC; NYSE: EMU)
Energy Metals follows a strategy of buying up proven producing mines in the US that have been shuttered; the company then reactivates these mines. The company’s most-advanced mine is on schedule to begin production in late 2007 at about 1 million pounds of U-308 annually.
But this is all old news. The most-interesting development for Energy Metals since my recommendation is that the company decided to pursue a US New York Stock Exchange (NYSE) listing. That makes it only the second dedicated uranium company to list on the NYSE; Cameco is the other one.
This listing makes it easier and more convenient for US investors to enter the stock. It also raises the company’s visibility.
Pitchstone Exploration (Toronto Venture: PXP)
Pitchstone is further along the risk curve. The company is still years from production, and its projects are very much in the exploration stages.
Cameco signed a letter of intent to jointly explore a series of properties in Gabon, Africa, with Pitchstone. The agreement gives both Cameco and Pitchstone the right to acquire 28 percent of the project in exchange for an initial investment of CD1.75 million. It’s this investment that gives me some confidence in Pitchstone’s prospects.
Pitchstone recently completed a private placement of shares and sold some warrants in SXR that it received as part of an exploration deal with that company. Now, Pitchstone has some $11 million in cash to work with. These deals eliminated the need to seek new financing near term; this removed a cloud hanging over the stock.
UNOR (Toronto Venture: UNI)
Riskier still is UNOR. Although this stock has been the worst performer in the uranium field bet since added in July, I still see the stock as a sleeper with lots of potential. Cameco thinks enough of UNOR to form a strategic alliance with it and purchase nearly 20 percent of its outstanding stock.
Cameco stated clearly in its first quarter call that it found the geological conditions in the region similarly attractive to the Athabasca Basin; Athabasca is the region where Cameco’s key mines are located. Cameco’s CEO went on to say that he believes UNOR has a solid technical team and a good land position in the region.
In late November, UNOR completed another private placement of shares with Cameco, raising more capital to help fund further exploration. I see this as yet another vote of confidence on Cameco’s part.
UEX Corp (Toronto: UEX)
UEX has actually been a separate play within the Gushers Portfolio for more than a year now. UEX Corp is partly owned by Cameco and has extensive exploration joint-venture agreements with both Cameco and Cogema.
Cogema is basically the uranium exploration arm of Areva and, by extension, the French government. The fact that the world’s two largest uranium producers are invested in the stock is enough to make it warrant attention.
The company has undertaken a very aggressive uranium exploration campaign in the Athabasca Basin, the same basic geographical area where prolific mines such as McArthur Lake are located. Cameco contributed some of these properties to UEX.
In early December, UEX announced a slew of drilling results. The results were again very promising; the company has identified some impressive uranium resources that look to be commercial. UEX plans another aggressive drilling program for 2007.
Uranium Participation Corp (Toronto: U)
Uranium Participation Corp isn’t a mining firm. Instead, this company simply owns physical U-308 and uranium hexafluoride (partly processed uranium). As of the end of December 14, the company owned 4.2 million pounds of U-308 and some 800,000 kilograms of uranium hexafluoride. Uranium participation stock allows individual investors to participate directly in the ownership of uranium.
The total value of the uranium products that Uranium Participation Corp owns is around CD9 to CD10 per share; the stock trades closer to CD12 to CD13. Therefore, this fund trades at a large premium to its net asset value (NAV).
Although this might normally be a problem for a fund, I’m not overly concerned in this case. The reason is simply that Uranium Participation Corp is nearly unique; there’s a scarcity premium on the stock.
Unlike gold, silver or other physical commodities, for obvious reasons, you can’t exactly buy and hold U-308 and uranium hexafluoride. Therefore, Uranium Participation Corp is the only way to buy into the story directly.
For those with access to the London market, a similar firm has listed on London’s Alternative Investment Market. This company, called Nufcor Uranium (London: NU), owns about 2 million pounds of uranium oxide and trades at about GBP2.89 per share. The company also trades at a premium to its NAV, though I’ve noticed the premium is slightly smaller.
Those with access to London should consider dividing their position between Uranium Participation and Nufcor.
Uranium Resources (OTC: URRE)
Uranium Resources is an actual uranium producer with mines in the US. The stock got slammed in September as a result of some production shortfalls and cost overruns. Nonetheless, the stock has recovered all those losses and then some in the ensuing three months.
Uranium Resources is a high-cost producer. But at $65-plus per pound available on the spot market, this company should be able to continue making money.
Biofuels
As the name suggests, biofuels are fuels made from organic products, typically crops like soybeans, corn and sugarcane. We’ve actually been playing the biofuels market for roughly a year now. I highlighted the industry at great depth in the Sept. 20, 2006, issue of TES Fueled By Food.
Just as with nuclear power, I recommend playing biofuels with a combination of established companies and the riskier, more-leveraged names included in my biofuel field bet.
The two most-common biofuels are ethanol and biodiesel. Ethanol is a distilled alcohol; the basic process for making the fuel differs only slightly from making whiskey or gin. In the US, it’s primarily made from corn, while in Brazil, it’s made mainly from sugarcane.
Biodiesel is made from vegetable oils. In Europe–currently the most-important biodiesel market–the fuel is made mainly from rapeseed. But it can also be produced from palm oil or soybean oil.
The key to the investment case for biofuels is to understand that they aren’t by any stretch of the imagination a solution to the world’s energy problems. Even if you converted the entire global soybean crop into biodiesel and all of the world’s corn into ethanol, the resulting biofuel wouldn’t be sufficient to replace more than 10 to 15 percent of conventional crude oil demand.
But the purpose of TES isn’t to solve the world’s energy problems. Rather, it’s to make money in the energy patch. Although we may not slake the world’s thirst for oil with prairie weeds, discarded bananas and palm oil, that doesn’t mean we can’t make money investing in such technologies.
The simple fact is that there are few subgroups in the energy sector with more growth potential than biofuels. Moreover, I can think of few sectors that are more insolated from commodity price volatility than ethanol and biodiesel.
The investment case for biofuels is simple: Biofuels are politically desirable. Governments the world over are pushing their use and mandating increased use in the coming years.
It’s easy to promote biofuels as an environmentally friendly fuel that can break dependence on foreign oil. Politically driven and subsidized production growth can continue even if overall energy demand moderates and oil falls further.
And for agricultural commodities, biofuels are only one piece of the demand puzzle. Consider that one of the most-prevalent consequences of economic growth is that consumers switch eating habits from basic staple foods like grains to start consuming more meat and processed food. To raise livestock requires significant feed; feed is made from grains and oilseeds.
The chart below reveals that Chinese meat consumption is now more than 20 percent of total calories consumed; in the US and parts of western Europe, that figure is closer to 30 percent.
Source: Food and Agriculture Organization of the United Nations
With China’s domestic agricultural industry straining to even maintain production, it should come as no surprise that China is becoming an increasingly important importer of agricultural commodities.
As emerging markets like China and India develop, consumption of grains rises exponentially. When you combine increased food demand with demand for biofuels, it’s easy to see the long-term investing case for agricultural commodities. For a more detailed treatment of this topic, please check out the September 20 issue of TES.
My longest-standing play on biofuels is agribusiness giant Bunge. (Please note that Bunge’s symbol is BG and fellow Wildcatters recommendation BG Group trades under the symbol BRG.)
Bunge is the world’s largest oilseed processor; it crushes crops like soybeans and rapeseed to make vegetable oils. The company is also a key player in the all-important South American market. Bunge is the number one fertilizer retailer in Brazil and has oilseed processing and export facilities there.
When I first recommended Bunge nearly a year ago, the company was still suffering from poor results in South America. The agricultural market in Brazil, and to some extent Argentina, was weak mainly because of the Brazilian real’s strength against the US dollar, coupled with weak prices for some key farm products. But those hiccups are passing.
The Brazilian government passed an aid package for farmers that helped shore up finances. And with the prices of key commodities rising, farm incomes have begun to improve.
This is particularly true of soybeans, one of the most-important crops grown in Brazil and the key crop for Bunge in South America. As the chart below shows, soybean prices have been rising rapidly as a result of expectations for smaller global crops next year. The company has also taken steps to improve its currency hedging program to make earnings less volatile.
Source: Bloomberg
Although Bunge definitely isn’t a pure play on biofuels, it does benefit from strong demand for crops. Demand for vegetable oils has been growing quickly in recent years, powered by demand from the emerging markets. And the company also produces crop products that are used as animal feed; Bunge directly benefits from growing meat consumption.
But I’m really excited about Bunge because it continues to target the biofuels market more aggressively, particularly the market for biodiesel. As noted above, biodiesel is made from vegetable oils; Bunge is the world’s largest producer of such oils. Therefore, it’s well-positioned to provide oils to biodiesel producers as a feedstock.
In fact, that’s exactly what the company has been doing. A deal with DuPont expands a joint venture between the two companies to include significant investments in biodiesel. DuPont’s Pioneer arm develops genetically modified seeds; newly engineered soybean seeds yield more oil (and biodiesel) per acre than conventional seeds.
The company also inked a deal with Renewable Energy Group for the production of biodiesel. In addition to supplying oil to this biodiesel producer, Bunge has also grabbed a minority stake in the business.
Bottom line: I see biofuels becoming an increasingly important source of demand for Bunge in future. I also see management continue to highlight this growth market by forming joint ventures with biodiesel producers all over the world. The company is actively encouraging biodiesel producers to sire their plants near Bunge crushing facilities to make it easier to supply these producers with feedstock. Continue buying Bunge.
In addition to Bunge, I recommend the following stocks
Although we’ve certainly made some money in traditional energy sectors related to oil and natural gas, the truly big gains this year have accrued to those willing to look beyond the ordinary. My favorite secular growth themes this year and into 2007 remain nuclear power and biofuels. Below I’ll review the basic themes and the latest news on my favorite plays.
And on the income front, master limited partnerships (MLPs) remain one of the most-overlooked and misunderstood asset classes in the market today; these partnerships also remain my top income idea for 2007 and beyond. Despite their stodgy image, MLPs have actually been a prime driver for portfolio returns in 2006.
Before I delve into today’s issue, a note to all new subscribers. In TES, I maintain three model Portfolios–Proven Reserves, Wildcatters and Gushers–each with a slightly different focus and strategy. The Proven Reserves Portfolio is really an income portfolio; the aim is high yield and relative stability. The Wildcatters Portfolio is my growth portfolio; my goal here is long-term capital appreciation.
Finally, there’s the Gushers Portfolio. This is really a trading/aggressive growth portfolio where I look for truly big gains and am willing to assume above-average risk. Subscribers should consider allocating money according to their risk tolerance and goals; the most-conservative investors may, for example, completely avoid the Gushers Portfolio and concentrate mainly on Proven Reserves. Those willing to take on more risk may, in contrast, allocate more capital to the Gushers plays.
In This Issue
Headlines have been declaring that warming effects of El Niño and an oversupply will be negative factors for natural gas this coming year. However, there are other factors to consider in this argument. See Weathering Gas.
Just as with natural gas, coal demand has also been impacted by the warmer temperatures. However, the coal industry is uniquely suited to handle such a demand decrease. See Coal Is King.
OPEC’s recent production cuts are not to be taken lightly. Given that the cartel would like to keep oil prices in the $55 to $60 range, I have some slightly different recommendations to maximize your gains in this industry. See Oil’s Well.
Because I tend to watch services and equipment companies focused on projects outside the US, I don’t see any of my recommendations in the Portfolios being significantly affected by energy prices. The seismic business is booming, and exploration activity is underway. See Services And Equipment.
Gains have been received in a variety of industries this year, but my three favorite secular themes remain nuclear energy, biofuels and MLPs. Here’s a rundown of how my recommendations in these fields have performed this year. See Secular Bull Market.
In this issue, I’m recommending or reiterating my recommendation on the following stocks:
- BG Group (NYSE: BRG)
- Biofuels field bet
- Bunge (NYSE: BG)
- Dresser-Rand (NYSE: DRC)
- Eagle Rock Energy Partners (NSDQ: EROC)
- EOG Resources (NYSE: EOG)
- Peabody Energy (NYSE: BTU)
- Petroleum Geo Services (NYSE: PGS)
- Schlumberger (NYSE: SLB)
- Tenaris (NYSE: TS)
- Uranium field bet
- XTO Energy (NYSE: XTO)
I’m also recommending avoiding or shorting the following stocks:
- Alpha Natural Resources (NYSE: ANR)
- Frontline (NYSE: FRO)
- International Coal Group (NYSE: ICO)
- James River Coal Co (NSDQ: JRCC)
- Massey Energy (NYSE: MEE)
- OMI (NYSE: OMM)
- Overseas Shipholding Group (NYSE: OSG)
Weathering Gas
I highlighted my basic outlook for the oil and gas markets at some length in the most-recent issue of The Energy Strategist, Looking for Some Upside. Since that time, there have been a series of unseasonably warm days all along the East Coast and Northeast. Because winter heating demand remains the prime driver of demand for gas, the warmer temperature has put pressure on natural gas prices and, to a lesser extent, crude oil prices.
That said, as I’ve pointed out before, I don’t regard the warm weather as a new revelation. The National Oceanographic and Atmospheric Association (NOAA) has been predicting that the presence of El Niño would result in a warmer-than-average winter this year since at least September. (I highlighted NOAA’s statement in the Oct. 18, 2006, issue of this newsletter.) This El Niño effect and the potential for another warm winter have been the subject of endless chatter and commentary among energy analysts and traders during the past three months.
A few points are worth noting, however. First, the actual text of NOAA’s winter weather prediction isn’t as bearish as some have argued. NOAA has predicted that the coming winter would be warmer than average but significantly colder than last year. Second, we actually saw some unseasonable cold snaps in October and November; the weather hasn’t been consistently warmer than average so far this season.
Further, warm spells could well continue to put pressure on energy prices. And for at least the next two months, energy futures traders will be keeping one eye on the thermometer.
But I continue to believe that we saw some important lows for both gas and oil in September and October. Remember, the warm winter scenario is no secret; the energy markets have largely priced in the potential for a warm winter. Well-known facts such as this rarely lead to profitable investments.
In addition, demand is only half the equation. There’s also the issue of supply. The simple fact is that natural gas inventories in the US remain above average for this time of year; this inventory hangover is a result of the record warm winter of 2005-06.
However, the inventory overhang in the US isn’t as large as it was six months ago. Despite the headlines, inventories have actually normalized a great deal since that time. And check out the chart below.
Source: US Energy Information Administration, Bloomberg
This chart depicts the weekly injection/withdrawal gas statistics. Injection refers to the addition of natural gas into US storage facilities; on the chart, gas is being injected into storage when the lines are in positive territory. Gas withdrawal refers to removing gas from storage (for use); this occurs when the lines are below zero.
I examined the past five years of weekly gas injection/withdrawal statistics for the US market. I plotted the largest figures, the lowest figures, the average and, of course, 2006 data on this chart. In calculating the average and high and low figures, I didn’t include this year’s data.
A few points here are worth noting. First, for roughly the first half of 2006, the US saw either lower-than-average withdrawals or higher-then-average injections. You’ll note that the light-blue line (representing this year’s data) tended to be significantly above the dark-blue, five-year average line up through roughly midyear. This was mainly because the 2005-06 winter was very warm and the spring was benign; demand for gas remained muted from January through June of 2006.
But there’s a notable shift after the first half of the year. Note in particular that we actually saw some gas withdrawals during the summer months. You can clearly see that this hasn’t occurred in any year in the past five years except for 2006.
This dip was the result of the extraordinarily hot summer weather experienced across much of the country in the summer of 2006. That weather resulted in record electricity demand. Because gas is an important source of electricity, the surge in demand actually resulted in a highly unusual midsummer gas withdrawal.
A casual glance at this chart also shows that, for the most part, the US withdrawal/injection line has been roughly at or below average since midyear. In other words, for most of late summer and early fall, gas injections were lower than normal. Moreover, since early fall, gas withdrawals have been higher than average.
Note that this chart doesn’t include the data for the very warm days in mid-December; data covering this period will be released later this week. I have no doubt that the past week has brought withdrawals of gas that are lower than average for this time of year. It’s even possible we’ll see net injections of gas during the past week. However, this hasn’t been the case for most of the fall months.
Bottom line: There are still plenty of gas bears citing excessive inventories as rationale for a drop in gas prices this winter. But the actual statistics suggest that gas inventories are gradually normalizing.
Then, of course, there’s Canada. As I pointed out last week, drilling activity in Canada has been weaker than average during the past few months.
Canada, unlike the US, has actually seen a year-over-year decline in drilling activity. Given the high well decline rates in Canada, this is surely impacting Canadian gas production. Perhaps that’s one reason why the Canadian gas inventory picture looks so much different from that of the US.
Source: Bloomberg
This chart shows actual gas in storage, not withdrawals and injections. Note that until early fall, Canadian natural gas inventories were running well above average and well above levels witnessed in the past three years. That’s because Canada, like the US, experienced a warmer-than-average winter last year.
But more recent, that picture has reversed. Canadian gas inventories have been running close to average levels and actually under average levels for much of the period in question. I suspect that the decline in Canadian drilling activity is already resulting in an impact on inventories despite warmer-than-average temperatures.
And if you’re wondering why Canadian gas inventories are important for the US market, consider that Canada is the US’s single-largest source of imported natural gas. A decline in the Canadian rig count will ultimately result in lower imports of gas and shrinking US inventories.
All these points reference only the US market. Europe is also a major market for natural gas; Europe is even more dependent on imported gas than the US is. And Europe relies heavily on natural gas supplies from Russia to meet domestic demand.
Russia has been in the news a great deal recently, and not all the reports have been the latest twist in the cloak-and-dagger Alexander Litvinenko poisoning scandal.
Specifically, some prominent pundits are arguing that by the end of this decade Russia won’t have enough natural gas to both meet domestic demand and honor all of its European export contracts. The increased urgency of Russia’s efforts to end subsidized pricing to former Soviet states suggests that there’s at least a kernel of truth to that argument.
I highlighted this Russian gas story at some length in the Oct. 5, 2006, issue of TES, Review And Preview. But it’s worth reviewing it here.
Gazprom is unique in that it’s Russia’s dominant gas producer and, therefore, has privileged access to the world’s largest gas reserves. The Russian government treats the firm somewhat like a national champion.
The firm currently makes most of its money by exporting gas to Western Europe. The prices it receives in Europe are based on a formula that ties the price of gas to the price of crude oil with somewhat of a time lag.
But in Russia’s domestic market and in other former Soviet-controlled states, Gazprom isn’t allowed to charge full world prices. Instead, the firm sells gas at subsidized rates that can be 20 percent or less the price Western Europe pays. Gazprom, needless to say, doesn’t make much money in these markets.
The problem is that subsidies create price distortions and undesirable behavior. Because the price of gas is so low in these domestic and regional markets, consumers use more gas than they otherwise would.
Booming demand in these “low-price” markets means less gas is available for Gazprom to export to “high-price” countries like Western Europe or even the US. With the Russian economy growing robustly the past few years, demand for gas has been growing at a particularly quick pace.
Just last week, Russia threatened to cut off natural gas supplies to both Belarus and Georgia if these countries failed to agree to pay far-higher gas prices next year. A year ago, Russia actually cut gas supplies to the Ukraine briefly as a negotiating chip to prompt the country to accept higher prices. The strategy worked to an extent, but Italy and parts of Germany nearly ran out of natural gas during the peak of the winter heating season as a result of the cuts.
Belarus has been politically friendlier toward Moscow than Georgia or the Ukraine. The nation has been paying $47 per thousand cubic meters for its natural gas supply against prices of $250 to $300 in Western Europe.
Now, Moscow wants to hike Belarus prices to $200. This is a dramatic price increase for a country that’s been seen as a political ally. Russia wants to more or less end all subsidies to former Soviet states by 2008; I suspect that there will also be a gradual push to end subsidies within Russia to domestic consumers as well.
I see two points worth noting about all this. One is that the gas supply situation outside the US remains tight.
The second is that a normalization of subsidized gas prices to more-competitive levels is good news for Gazprom. I’ve been eyeing this company as a potential portfolio addition; as the chart below shows, the stock has been trading sideways for some time now.
Source: Bloomberg
To make a long story short, I recognize the importance of weather to the short-term picture. However, I’m not convinced by the simplistic arguments about El Niño and massive gas oversupply.
Although I’m certain we’ll see more volatility in the next two weeks, I remain comfortable holding gas-focused exploration & production (E&P) firms EOG Resources, BG Group and XTO Energy. I outlined my case for owning these companies in the most-recent issue of TES, Looking For Some Upside.
Back To In This Issue
Coal Is King
Coal prices and coal stocks have been somewhat leveraged to natural gas prices recently. This stands to reason as coal is the most-important fuel for electric power plants in the US.
The winter heating season marks a period of heavy coal demand just as it’s a time of peak natural gas usage. Therefore, the recent warm weather has also reduced coal demand.
Coal spot prices have certainly declined since the spring. But that decline lost steam this fall; prices for all types of spot coal have been more or less flat the past few months.
And remember that coal-mining firms aren’t totally tied to the price of the commodity itself. Most of the coal miners sell their production as part of long-term contracts; big, reliable producers can often sign these contracts at a significant price premium to the widely quoted “spot” rate.
In addition, although coal prices are now lower than they were in May, they’re significantly higher than spot prices two to three years ago.
Coal mining firms are constantly rolling over their long-term contracts. In other words, when an old supply contract expires, coal-mining firms will go out and reprice that production on a new multi-year deal. Therefore, some of the contracts still being honored today were priced back in 2000-03, when coal prices were far lower than right now.
For example, the management at Arch Coal provided some nice statistics in its late-October conference call. The company stated that it’s been signing contracts for 2007 coal deliveries from the Powder River Basin (PRB) at prices 25 percent higher than its average realized coal price in the third quarter of this year.
For coal contracts covering its highest-value Western coals, Arch is signing contracts prices for delivery as far out as 2010, some 50 percent above its current realized prices. Therefore, as companies roll over these low-priced legacy contracts to more market-based rates, earnings will continue to benefit.
On the supply front, costs to mine in the Appalachian coal region continue to rise, rendering many operators in the region unprofitable. Supply from Central Appalachia is likely to continue falling; softer supply growth will also put a floor under prices.
The real growth in production will come from the Western US PRB. Mining costs in the PRB are also rising but at a far-more-muted pace than in the East.
Bottom line: Shifts in sentiment surrounding the weather will continue to affect Wildcatters recommendation Peabody Energy. Nonetheless, the intermediate- to longer-term bullish case is intact; I continue to rate Peabody a buy.
For more specific analysis of this stock, check out the November 1 issue of TES, Earnings Bonanza.
For the record, all miners focused on Appalachian mining–including Alpha Natural Resources, James River Coal Co, Massey Energy and International Coal Group–should be avoided. These companies don’t have the potential to grow production as quickly as Peabody, and costs in Central Appalachia are rising rapidly; profit margins have been severely squeezed in the East.
I’ve been recommending avoidance of all these names since the end of 2005, and my outlook is unchanged.
Back To In This Issue
Oil’s Well
Winter weather does have an impact on oil prices. In some parts of the country, notably the Northeast, heating oil is still widely used. Demand for heating oil tends to ramp up during the winter months, just like demand for natural gas. The summer driving season is a more-important period for oil consumption, but heating demand is relevant.
Warm winter weather has cooled demand for heating oil. Interesting, however, warm weather has also encouraged traveling and gasoline demand has been higher than normal for this time of year. The US oil gasoline demand picture still looks robust near term.
Far more interesting is what’s been happening on the supply front recently. The Organization of Petroleum Exporting Countries (OPEC) agreed to reduce output by 1.2 million barrels per day on November 1.
Many pundits chose to ignore that cut, saying that OPEC was simply trying to talk up oil prices and there would be no real action. As I stated on multiple occasions, I disagree with that view.
The reason is simple: A weak tanker market suggests reduced demand for oil transport from the Persian Gulf. (I highlighted this phenomenon at some length in a November 30 Flash Alert, Tankers, Airlines, Oil And Gas.) Check out the Baltic Dirty Index chart of tanker rates below.
Source: Bloomberg
This chart shows tanker rates over the past four years normalized to fit on one chart. Typically, tanker rates surge from the August-September months straight through the end of the year.
But this year has been different. Tanker rates continued to slide lower in the late summer and early fall, bucking the seasonal uptrend. And although rates have jumped higher this month, 2006 tanker rates are lower than in any other year covered by this chart.
The worst of the weakness seems to be in the very large crude carrier (VLCC) market. These are the primary tankers used to haul oil from the Middle East to the US and Asia.
Tanker rates typically rise when the Middle East is shipping a good deal of oil. This very weak fourth quarter picture suggests that the OPEC supply cuts may be more than meaningless rhetoric. At any rate, there’s been a meaningful decline in oil shipped by tankers lately. Ultimately, this will filter though in the form of lower domestic supply.
At OPEC’s December 14 meeting, the organization agreed to another 500,000-barrels-per-day cut in output to take effect February 1. Check out the text of the statement following that meeting:
Having reviewed the oil market outlook, including the overall demand/supply expectations for the year 2007, in particular the first and second quarters, as well as the outlook for the oil market in the medium term, the Conference observed that market fundamentals clearly indicate that there is more than ample crude supply, high stock levels and increasing spare capacity. The Conference noted that, although the global economy is forecast to continue to grow, economic growth is expected to slow down in 2007. Moreover, while world oil demand is estimated to increase by 1.3 mb/d in 2007, the Conference observed that this is likely to be more than offset by a projected increase of 1.8 mb/d in non-OPEC supply, its highest rise since 1984.
The Conference also noted, with satisfaction, that the decision it had taken in Doha to reduce production by 1.2 mb/d as of 1 November 2006 had succeeded in stabilizing the market and bringing it into balance, although prices remain volatile, reflecting the continuing supply overhang in the market.
In view of the above, the Conference decided to reduce current OPEC production by 500,000 b/d, with effect from 1 February 2007, in order to balance supply and demand. The Conference further reiterated the Organization’s determination to take all measures deemed necessary to keep market stability through the maintenance of supply and demand in balance, for the benefit of producers and consumers alike. Concurring on the need, more than ever, for extreme vigilance in assessing the market during the coming months, the Conference also confirmed that its next Ordinary Meeting will be held on 15 March 2007, in Vienna, Austria. — 143rd Extraordinary Meeting of the OPEC Conference; Abuja, Federal Republic of Nigeria; 14 December 2006
OPEC remains vigilant about the potential for non-OPEC oil production to grow next year. The organization appears more than willing to discuss further supply cuts in an effort to keep oil prices above the $55 to $60 per barrel level.
These points all support my view that oil prices will remain well supported in the $55 to $60 region. The only real risk I see to crude is a major global recession in the latter part of 2007; it’s too early to start forecasting such a slowdown.
Nonetheless, the prospect of further OPEC supply cuts isn’t good news for the tanker firms. Already, the lower-than-normal fourth quarter tanker rates are likely to result in some downside surprises to earnings.
In the Proven Reserves Portfolio, I currently recommend General Maritime as part of what’s known as a pair trade. I recommend shorting another tanker firm–OMI–to hedge the potential for downside in GenMar.
Because GenMar offers dividends well in excess of OMI, this pair trade allows us to capture GenMar’s dividends while protecting our position against a general decline in the tanker sector. The short in OMI should help guard against declines.
Also, because Genmar focuses more on the Atlantic basin tanker market and smaller tanker ships, it’s less exposed to OPEC supply cuts than firms with concentrated exposure to the VLCC market. This is precisely why I recommended selling out of Frontline in the November 30 Flash Alert. Frontline had previously been a trade in my aggressive Gushers Portfolio.
Frontline is still the best of breed in the VLCC tanker space. If you wish to continue holding Frontline as a long-term income play, I recommend shorting Overseas Shipholding Group (NYSE: OSG), another VLCC-focused tanker company, as a hedge against your Frontline holdings.
If the tankers all keep falling, gains in your Overseas Shipholding short should offset losses in Frontline. Overseas Shipholding pays only a meager dividend yield compared to Frontline’s giant payout.
When you are short a stock, you must pay dividends in lieu of the company. That makes shorting Frontline for any length of time impractical; the company’s dividends are just too high. But Overseas Shipholding has consistently followed a low dividend policy.
Given the recent weakness in tanker shipping rates and the prospect for more OPEC cuts, Overseas Shipholding is now a short recommendation in the Gushers Portfolio.
Just to clarify my position, I continue to recommend General Maritime as a buy using OMI as a short hedge. I’m now also recommending a short in Overseas Shipholding; the company is uniquely leveraged to this year’s unusually weak tanker market. I see downside in Overseas Shipholding to under $50 by the first quarter of 2007.
Back To In This Issue
Services And Equipment
There’s been some knee-jerk selling in most of the services and equipment firms related to the warm weather. That said, I don’t believe that the services and equipment companies recommended in TES will have much actual earnings downside, even if a warmer-than-normal winter this year were to result in further downside to US gas prices.
This is because I recommend avoiding services and equipment firms that are overly leveraged to the US and Canadian markets. North America is far and away the most-volatile drilling market; projects tend to be small scale and short-term. That means that, as we’ve witnessed in Canada this year, drilling activity can be quite sensitive to commodity prices.
In contrast, international projects tend to be longer-term, major projects. Even a relatively large decline in oil and gas prices wouldn’t have a huge effect on activity.
In the most-recent issue of TES, I offered my bullish case for owning Tenaris, the largest global manufacturer of oil country tubular goods (OCTG). The stock is up some 35 percent since my original recommendation and is up considerably just since my last mention on December 6, partly as a result of some unconfirmed rumors that Gazprom may try to acquire Tenaris.
Although I continue to like the company fundamentally, these rumors have pushed the stock above my buy-under target. I’d only look to enter Tenaris on a dip toward my recommended target of 48.
In addition, I’m raising my recommended stops to lock in gains. For those subscribers willing and able to trade options, I recommend an options strategy for locking in gains on Tenaris while leaving room for plenty of upside. The strategy will be detailed in a flash alert I’ll be sending out in the next two weeks.
I outlined my rationale for recommending Petroleum Geo Services in the November 1 issue of TES. As this company’s main business is seismic surveys outside the US market, I don’t see that it has much real downside no matter what happens to US gas prices.
Recall that seismic surveys involve using sound waves to generate a sort of map of underground rock formations and potential petroleum reservoirs. Seismic surveys are a key feature of any exploration activity. As oil and gas prices remain high by historical standards, producing firms have stepped up their exploration activity of late.
Bottom line: The seisimic business is booming, and Petroleum Geo Services remains in the sweet spot of that trend. I’m maintaining my buy rating on Petroleum Geo; note the raised stop recommendation.
I highlighted both Dresser-Rand and Schlumberger in the December 6 and November 22 issues of TES, respectively. I won’t repeat my arguments here. Both Dresser and Schlumberger remain buy recommendations.
Back To In This Issue
Secular Bull Markets
Oil, gas, services and coal stocks have certainly handed us some nice gains in recent months. But by far the biggest percentage gains have come from my three favorite secular themes: nuclear energy, biofuels and MLPs.
These remain my favorite themes for 2007–all should continue to perform well regardless of the action in oil and gas prices. It’s worth offering a brief recap and review of each theme in turn.
Nuclear Power
I offered a detailed and comprehensive look at the nuclear industry in the July 26, 2006, issue of TES, The Nuclear Option. I recommend that all new subscribers to the newsletter and all investors unfamiliar with nuclear power and the uranium market review that issue, which is available in the archives.
In brief, nuclear energy is a clean, cheap and reliable source of power. The demand for electricity is actually growing faster than the demand for transportation fuel in most developed and developing markets. Countries like China and India are seeing demand for electricity grow particularly quickly–at many times, the rate of US demand growth.
Although North American consumption of power is projected to double between 1990 and 2030, non-Organisation for Economic Co-operation and Development (OECD) countries should see demand rise by close to a factor of five over the same time period. Meanwhile, Indian power demand is set to rise by a factor of seven; Chinese demand is expected to increase by more than 10 times.
These trends in the developing world should come as little surprise. The simple fact is that, as nations develop and become wealthier, demand for electricity accelerates.
Consumers in China are starting to buy the same types of household appliances, such as air conditioners and refrigerators, as their counterparts in the Western world. The changes are coming at a rapid pace. According to the Chinese government, more than 80 percent of Chinese urban households have air conditioning, up from around 30 percent just five years ago.
All of these basic consumer appliances require electricity, powering a massive increase in demand. Demand has risen so rapidly, in fact, that Chinese power generators are having considerable difficulty keeping pace; there have been reports of widespread power blackouts in China during the past few years.
And, as is the case in the US, demand for electricity worldwide is growing faster than demand for oil. For example, according to the Energy Information Administration, Chinese oil demand will grow approximately 3.8 percent annually between 2003 and 2030. Meanwhile, electricity demand over the same period is set to grow at 4.8 percent annualized, a full percentage point faster.
Although China and India could rely on coal to meet this demand, that’s not an attractive option. Heavy reliance on less-efficient coal plants is taking a toll: Of the 10 most-polluted cities in the world, seven are located in China. It’s estimated that acid rain falls on more than a third of the country, causing damage to crops.
Smog and respiratory illness are also more common in China than in most of the developed world. In fact, in some cities, the smog and soot are so thick that cars typically drive with their headlights on during daylight hours.
Although gas is a cleaner option than coal, most countries with rapidly growing demand just don’t have enough gas production domestically to meet their needs. That means importing natural gas from abroad in the form of liquefied natural gas (LNG).
LNG imported from places such as Russia and the Middle East carries significant supply risk and, most likely, a fair degree of political risk. In addition, more than 70 percent of the cost of generating power in gas-fired plants is the cost of the gas itself; with gas prices at current levels, it’s an expensive source of power.
A Finnish government study conducted in 2000 examined the change in electricity costs for coal, nuclear and gas-fired plants. The study concluded that a doubling in uranium prices would result in a 9 percent jump in the cost of nuclear-generated power.
But a doubling in coal and natural gas costs would cause a 31 percent and 66 percent rise in electricity costs, respectively. Even the rapid rise in uranium prices in recent years has done little to change the economics of nuclear power production.
The key fuel for nuclear power plants is uranium. Bottom line: There’s a supply squeeze of epic proportions underway in the uranium market; uranium remains perhaps the tightest commodity market on Earth right now.
Consider that, in 2005, the world consumed roughly 175 million pounds of uranium, while total mine production was just 110 million pounds. That 65 million pound deficit was covered by a combination of reprocessed nuclear warheads and inventories of uranium owned by utilities and the government. But inventories are now running low, and the deal with Russia to reprocess nuclear warheads into plant fuel is set to end soon.
To make matters worse, as I highlighted in an October 26 Flash Alert, the world’s largest supplier of uranium, Cameco, experienced a major flooding problem at its Cigar Lake mine in Canada. Originally, Cameco had planned production from Cigar Lake beginning in 2008; this flood will delay production for at least one year.
Although a one-year delay at a single mine may not seem like a big deal, keep in mind that this single mine was set to produce about 10 percent of global uranium demand within a few years of opening. Therefore, the loss of the Cigar Lake production is the rough equivalent of taking Saudi Arabia out of the world oil market.
Consider that in late July uranium oxide (yellowcake) was trading around $47 per pound; lately, uranium has surged to more than $70 per pound. And at the beginning of 2006, uranium was trading in the mid-30s per pound. In fact, uranium prices haven’t declined week over week since 2003.
With the current supply of mined uranium falling well short of demand, utilities have been running down their inventories of uranium to meet needs. For the most part, utilities built up their inventories during the low price environment of the 1980s and ’90s; with inventories disappearing, utilities need to contract new supply.
And that doesn’t even count the added demand that will come from all the new nuclear plants scheduled for construction in the next decade-and-a-half.
This is only a brief overview and review of the uranium story. Suffice it to say that I believe the uranium bull market remains in its early stages.
There will be corrections along the way, but I’m looking for the spot price of uranium oxide to exceed $100 per pound by the end of this decade. Increasingly, this $100 target is looking conservative; I see the risks to the upside. For a more complete treatment, please check out the July 26 issue of TES.
I recommend two primary ways to play uranium: Cameco and what I call my uranium field bet. As noted above, Cameco is the world’s largest uranium producer. The company produces more than 21 million pounds of uranium oxide (U-308) annually; that’s nearly a fifth of total global production in 2005.
In addition, Cameco sits atop some of the world’s richest mines and has some excellent projects (including Cigar Lake) that will likely begin production in the next three to five years. In many ways, Cameco is the ExxonMobil (NYSE: XOM) of uranium, only far more dominant and important to its market.
Cameco is up more than 100 percent from my original recommendation in 2005 but hasn’t performed particularly well lately; we’re up just 7 percent since midyear. There are two main reasons for that. The first is the considerable uncertainty surrounding the company’s Cigar Lake project; it will likely be two months or more before we get a better picture of exactly how long this project will be delayed.
Second, and more important, Cameco suffers from legacy contracts. Just as with the coal mining firms, this company does very little trading on the illiquid uranium spot market. Instead, it contracts with utilities to supply uranium over long-term contracts–sometimes five years or more in duration.
Five years ago, with uranium trading under $10 per pound, a long-term supply contract signed in the low to mid-teens per pound would have been considered a real coup for Cameco. The company always did pride itself on obtaining premium pricing; the company, despite recent production issues, remains one of the world’s most-reliable suppliers.
But with uranium now in the mid-60s, those contracts signed five year ago look hopelessly anachronistic. It will take years for Cameco to work through all its legacy contracts; as these contracts are rolled over, the company’s realized uranium sale price will gradually rise.
But for now, the average price the company receives for its uranium is far under the current spot price. This is an elaborate way of saying that Cameco has only limited upside leverage to uranium price increases.
As a result, I’m cutting Cameco to a hold recommendation in this issue; I recommend new subscribers steer clear of the stock.
My second way of playing uranium is the uranium field bet. I recommend that subscribers concentrate their uranium investments on this play right now.
The concept of the uranium field bet is quite simple: Unlike Cameco, some smaller so-called “junior” uranium companies don’t have many legacy contracts to contend with. In many cases, these juniors are only just starting production or are still years away from production. Therefore, they have more upside leverage to uranium prices than Cameco itself.
That said, juniors also carry far higher risks. Uranium mining is a risky business. Production delays, unforeseen project cost and simple labor and raw materials inflation can all have important effects on the economics of a particular mining project. And production costs vary wildly depending on the grade of ore mined and how large overall reserves are.
Riskier still is exploration. Uranium explorers buy acreage and drill holes, taking core samples to evaluate reserve size and ore grades. Sometimes, even the most-promising reserves just don’t pan out and can never reach economic production. It’s impossible to know this for sure until you’ve spent considerable sums on exploration; only when uranium is produced can we really know for sure the full costs and viability of a project.
For the best chance at big returns, I recommend casting a wide net: Instead of just buying one or two high-risk names, I recommend placing a smaller amount in five to 10 such companies. I call this the uranium field bet.
Below is a table outlining my current uranium field bet selections. The returns listed in the table are the returns since I first recommended the stocks in the newsletter.
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Uranium Field Bet
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Company Name (Exchange: Symbol)
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Recent Price
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Market Cap. (in millions)
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Total Return
|
Advice
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| Paladin Res. (Australia: PDN; Toronto: PDN) | CD7.15 | CD3536 | 92.8% | Buy |
| SXR Uranium One (Toronto: SXR) | CD14.97 | CD1,991 | 60.0 | Buy |
| Energy Metals (Toronto: EMC; NYSE: EMU) | CD9.80 | CD650 | 66.7 | Buy |
| Pitchstone Exp. (Toronto V: PXP) | CD2.80 | CD79.5 | 73.9 | Buy |
| UNOR (Toronto V: UNI) | CD0.42 | CD49.3 | -22.2 | Buy |
| UEX (Toronto: UEX) | CD5.56 | CD1,006 | 88.0 | Buy |
| Uranium Part. (Toronto: U) | CD12.49 | CD605.3 | 48.9 | Buy |
| Uranium Resources (OTC: URRE) | USD6.14 | USD317.4 | 23.9 | Buy |
Source: Bloomberg, The Energy Strategist
For my rationale for owning these stocks, review the July 26 issue. Here’s a brief rundown of recent news on my uranium field bet picks:
Paladin Resources (Australia: PDN; Toronto: PDN)
Paladin is an Australian company with dual listing under the symbol PDN in both Australia and Canada; I’ve offered the Canadian symbol because it’s easier for most US investors to buy. Paladin has one of the most-advanced slates of uranium projects of any company anywhere in the world.
Paladin’s Langer Heinrich uranium project in Namibia was commissioned in September and began producing ore. The final construction on the project is scheduled for December 2006 with the first uranium sales from the mine slated for the first quarter of 2007.
The mine should hit its initial target of 2.6 million annualized pounds of U-308 by the third quarter of 2007. When you consider just how supply-constrained the global uranium market is, 2.6 million pounds is a considerable quantity. Moreover, Paladin is one of the only producers anywhere in the world that will bring new production online this year.
In addition to Langer Heinrich, Paladin has development projects in Africa and Australia that are ongoing. These could well result in further production in the next two to five years. Paladin remains one of my favorite uranium plays.
SXR Uranium One (Toronto: SXR)
SXR is like Paladin–an actual emerging producer. The company’s Dominion Uranium project in South Africa is scheduled to begin production in the first quarter of 2007; SXR announced a contract to sell 1.5 million pounds of uranium from the mine between 2008 and 2012. The contract is with an unspecified “western” utility company.
Better still, the contract wasn’t signed at a fixed price; the sales price for this uranium will be based on prevailing spot prices at the time of delivery. There’s even an escalating price floor for uranium prices under the contract. This is another clear sign of the pricing power emerging producers like SXR and Paladin have over their customers.
The Dominion project should begin production at the rate of 2 million pounds annually in 2007. There’s potential to further boost production to around 4 million pounds annually by 2011.
SXR also has a mining lease on the Honeymoon uranium project in South Australia. Actual production is scheduled for 2008 and will total roughly 900,000 pounds annually.
Energy Metals (Toronto: EMC; NYSE: EMU)
Energy Metals follows a strategy of buying up proven producing mines in the US that have been shuttered; the company then reactivates these mines. The company’s most-advanced mine is on schedule to begin production in late 2007 at about 1 million pounds of U-308 annually.
But this is all old news. The most-interesting development for Energy Metals since my recommendation is that the company decided to pursue a US New York Stock Exchange (NYSE) listing. That makes it only the second dedicated uranium company to list on the NYSE; Cameco is the other one.
This listing makes it easier and more convenient for US investors to enter the stock. It also raises the company’s visibility.
Pitchstone Exploration (Toronto Venture: PXP)
Pitchstone is further along the risk curve. The company is still years from production, and its projects are very much in the exploration stages.
Cameco signed a letter of intent to jointly explore a series of properties in Gabon, Africa, with Pitchstone. The agreement gives both Cameco and Pitchstone the right to acquire 28 percent of the project in exchange for an initial investment of CD1.75 million. It’s this investment that gives me some confidence in Pitchstone’s prospects.
Pitchstone recently completed a private placement of shares and sold some warrants in SXR that it received as part of an exploration deal with that company. Now, Pitchstone has some $11 million in cash to work with. These deals eliminated the need to seek new financing near term; this removed a cloud hanging over the stock.
UNOR (Toronto Venture: UNI)
Riskier still is UNOR. Although this stock has been the worst performer in the uranium field bet since added in July, I still see the stock as a sleeper with lots of potential. Cameco thinks enough of UNOR to form a strategic alliance with it and purchase nearly 20 percent of its outstanding stock.
Cameco stated clearly in its first quarter call that it found the geological conditions in the region similarly attractive to the Athabasca Basin; Athabasca is the region where Cameco’s key mines are located. Cameco’s CEO went on to say that he believes UNOR has a solid technical team and a good land position in the region.
In late November, UNOR completed another private placement of shares with Cameco, raising more capital to help fund further exploration. I see this as yet another vote of confidence on Cameco’s part.
UEX Corp (Toronto: UEX)
UEX has actually been a separate play within the Gushers Portfolio for more than a year now. UEX Corp is partly owned by Cameco and has extensive exploration joint-venture agreements with both Cameco and Cogema.
Cogema is basically the uranium exploration arm of Areva and, by extension, the French government. The fact that the world’s two largest uranium producers are invested in the stock is enough to make it warrant attention.
The company has undertaken a very aggressive uranium exploration campaign in the Athabasca Basin, the same basic geographical area where prolific mines such as McArthur Lake are located. Cameco contributed some of these properties to UEX.
In early December, UEX announced a slew of drilling results. The results were again very promising; the company has identified some impressive uranium resources that look to be commercial. UEX plans another aggressive drilling program for 2007.
Uranium Participation Corp (Toronto: U)
Uranium Participation Corp isn’t a mining firm. Instead, this company simply owns physical U-308 and uranium hexafluoride (partly processed uranium). As of the end of December 14, the company owned 4.2 million pounds of U-308 and some 800,000 kilograms of uranium hexafluoride. Uranium participation stock allows individual investors to participate directly in the ownership of uranium.
The total value of the uranium products that Uranium Participation Corp owns is around CD9 to CD10 per share; the stock trades closer to CD12 to CD13. Therefore, this fund trades at a large premium to its net asset value (NAV).
Although this might normally be a problem for a fund, I’m not overly concerned in this case. The reason is simply that Uranium Participation Corp is nearly unique; there’s a scarcity premium on the stock.
Unlike gold, silver or other physical commodities, for obvious reasons, you can’t exactly buy and hold U-308 and uranium hexafluoride. Therefore, Uranium Participation Corp is the only way to buy into the story directly.
For those with access to the London market, a similar firm has listed on London’s Alternative Investment Market. This company, called Nufcor Uranium (London: NU), owns about 2 million pounds of uranium oxide and trades at about GBP2.89 per share. The company also trades at a premium to its NAV, though I’ve noticed the premium is slightly smaller.
Those with access to London should consider dividing their position between Uranium Participation and Nufcor.
Uranium Resources (OTC: URRE)
Uranium Resources is an actual uranium producer with mines in the US. The stock got slammed in September as a result of some production shortfalls and cost overruns. Nonetheless, the stock has recovered all those losses and then some in the ensuing three months.
Uranium Resources is a high-cost producer. But at $65-plus per pound available on the spot market, this company should be able to continue making money.
Biofuels
As the name suggests, biofuels are fuels made from organic products, typically crops like soybeans, corn and sugarcane. We’ve actually been playing the biofuels market for roughly a year now. I highlighted the industry at great depth in the Sept. 20, 2006, issue of TES Fueled By Food.
Just as with nuclear power, I recommend playing biofuels with a combination of established companies and the riskier, more-leveraged names included in my biofuel field bet.
The two most-common biofuels are ethanol and biodiesel. Ethanol is a distilled alcohol; the basic process for making the fuel differs only slightly from making whiskey or gin. In the US, it’s primarily made from corn, while in Brazil, it’s made mainly from sugarcane.
Biodiesel is made from vegetable oils. In Europe–currently the most-important biodiesel market–the fuel is made mainly from rapeseed. But it can also be produced from palm oil or soybean oil.
The key to the investment case for biofuels is to understand that they aren’t by any stretch of the imagination a solution to the world’s energy problems. Even if you converted the entire global soybean crop into biodiesel and all of the world’s corn into ethanol, the resulting biofuel wouldn’t be sufficient to replace more than 10 to 15 percent of conventional crude oil demand.
But the purpose of TES isn’t to solve the world’s energy problems. Rather, it’s to make money in the energy patch. Although we may not slake the world’s thirst for oil with prairie weeds, discarded bananas and palm oil, that doesn’t mean we can’t make money investing in such technologies.
The simple fact is that there are few subgroups in the energy sector with more growth potential than biofuels. Moreover, I can think of few sectors that are more insolated from commodity price volatility than ethanol and biodiesel.
The investment case for biofuels is simple: Biofuels are politically desirable. Governments the world over are pushing their use and mandating increased use in the coming years.
It’s easy to promote biofuels as an environmentally friendly fuel that can break dependence on foreign oil. Politically driven and subsidized production growth can continue even if overall energy demand moderates and oil falls further.
And for agricultural commodities, biofuels are only one piece of the demand puzzle. Consider that one of the most-prevalent consequences of economic growth is that consumers switch eating habits from basic staple foods like grains to start consuming more meat and processed food. To raise livestock requires significant feed; feed is made from grains and oilseeds.
The chart below reveals that Chinese meat consumption is now more than 20 percent of total calories consumed; in the US and parts of western Europe, that figure is closer to 30 percent.
Source: Food and Agriculture Organization of the United Nations
With China’s domestic agricultural industry straining to even maintain production, it should come as no surprise that China is becoming an increasingly important importer of agricultural commodities.
As emerging markets like China and India develop, consumption of grains rises exponentially. When you combine increased food demand with demand for biofuels, it’s easy to see the long-term investing case for agricultural commodities. For a more detailed treatment of this topic, please check out the September 20 issue of TES.
My longest-standing play on biofuels is agribusiness giant Bunge. (Please note that Bunge’s symbol is BG and fellow Wildcatters recommendation BG Group trades under the symbol BRG.)
Bunge is the world’s largest oilseed processor; it crushes crops like soybeans and rapeseed to make vegetable oils. The company is also a key player in the all-important South American market. Bunge is the number one fertilizer retailer in Brazil and has oilseed processing and export facilities there.
When I first recommended Bunge nearly a year ago, the company was still suffering from poor results in South America. The agricultural market in Brazil, and to some extent Argentina, was weak mainly because of the Brazilian real’s strength against the US dollar, coupled with weak prices for some key farm products. But those hiccups are passing.
The Brazilian government passed an aid package for farmers that helped shore up finances. And with the prices of key commodities rising, farm incomes have begun to improve.
This is particularly true of soybeans, one of the most-important crops grown in Brazil and the key crop for Bunge in South America. As the chart below shows, soybean prices have been rising rapidly as a result of expectations for smaller global crops next year. The company has also taken steps to improve its currency hedging program to make earnings less volatile.
Source: Bloomberg
Although Bunge definitely isn’t a pure play on biofuels, it does benefit from strong demand for crops. Demand for vegetable oils has been growing quickly in recent years, powered by demand from the emerging markets. And the company also produces crop products that are used as animal feed; Bunge directly benefits from growing meat consumption.
But I’m really excited about Bunge because it continues to target the biofuels market more aggressively, particularly the market for biodiesel. As noted above, biodiesel is made from vegetable oils; Bunge is the world’s largest producer of such oils. Therefore, it’s well-positioned to provide oils to biodiesel producers as a feedstock.
In fact, that’s exactly what the company has been doing. A deal with DuPont expands a joint venture between the two companies to include significant investments in biodiesel. DuPont’s Pioneer arm develops genetically modified seeds; newly engineered soybean seeds yield more oil (and biodiesel) per acre than conventional seeds.
The company also inked a deal with Renewable Energy Group for the production of biodiesel. In addition to supplying oil to this biodiesel producer, Bunge has also grabbed a minority stake in the business.
Bottom line: I see biofuels becoming an increasingly important source of demand for Bunge in future. I also see management continue to highlight this growth market by forming joint ventures with biodiesel producers all over the world. The company is actively encouraging biodiesel producers to sire their plants near Bunge crushing facilities to make it easier to supply these producers with feedstock. Continue buying Bunge.
In addition to Bunge, I recommend the following stocks
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