As I explain below, I’m looking for crude to rally back toward the USD60 a barrel area by midsummer, and I’m looking for gas prices to double by fall. I’m more bullish than I’ve been in many months, despite continued weak economic data from the US.
You won’t hear alarm bells go off, and nobody will stand up on the evening news and declare the bottom’s been established. It’s not that easy. But there are signs out there. See Glimpse of A Turn.
Getting it right over the long term involves understanding how and why you erred in the past. Although it hasn’t been disastrous, my call to favor natural gas over oil hasn’t played out the way I had hoped. I explain why, and what that explanation tells us as we prepare for the future. See Natural Gas.
What does agriculture have to do with energy? And how do we profit at that intersection? See Farming for Profit.
We were stopped out of Portfolio recommendation Eni (NYSE: ENI) earlier this month. See Portfolio Update.
Market bottoms are rarely a clean, straightforward process. But, for the first time in many months, I’m seeing real signs that the outlook for oil, natural gas and related stocks is turning for the better. At the very least it appears the bad news that’s been plaguing the sector since last summer is priced into stocks.
As long-time Energy Strategist readers know, I’ve been negative on the outlook for the US economy for more than a year now. My favored indicator of economic health is the Index of Leading Economic Indicators (LEI), published monthly by the Conference Board. I see absolutely no sign of a durable turn for the US economy in the most recent LEI, and I suspect we won’t see such an improvement before midyear at the very earliest. Demand destruction due to economic weakness has been the main fundamental downside driver for oil, natural gas and other commodity prices in recent months–the weak US economy remains a headwind.
The economy was already weak heading into late summer 2008, but the situation deteriorated rapidly as the credit crunch really took hold in the fall and catalyzed an outright collapse in commodity prices through early December. To make matters worse, the credit crunch prompted institutional investors to liquidate positions in energy commodities and related stocks en masse to raise cash. Because many of these players used significant margin, the downside impact was magnified.
Over the past few issues I’ve noted a few glimmers of hope that, perhaps, the fundamental outlook for oil and gas was beginning to stabilize and improve. As noted in the Feb. 4 issue, energy-levered stocks started to outperform the broader market and energy commodities in late November. This pattern has largely continued in recent weeks check out my charts below for a closer look.
The first chart shows the relative strength of the S&P 500 Energy Index against the S&P 500 going back to late August; a rising line indicates energy-related stocks in the S&P 500 are outperforming the broader market. The second chart shows the relative strength of the Philadelphia Oil Services Index (OSX) to the S&P 500; again, a rising line means the OSX is beating the S&P 500.
Depending on which index you prefer to follow, energy stocks began outperforming the broader stock market sometime between mid-October and early December of last year. Another way to look at this is that the S&P 500 broke down to a new 12-year low in early March, while both the S&P 500 Energy Index and the OSX managed to basically hold their lows from the fall of 2008.
Of course, these charts show relative strength, not absolute strength; in other words, energy stocks have simply not fallen as far as the S&P 500 in recent months. However, relative strength is important–sectors showing solid relative strength during downturns often turn out to be leaders of ensuing recoveries.
In the last issue, I outlined some more meaningful fundamental signs of improvement in the energy markets. Here are some of the main factors I discussed:
· The big build in US oil inventories that began late last year began to reverse in early February. Inventories for motor gasoline are, in fact, looking relatively tight.
· Some of the weekly demand figures from the Energy Information Administration (EIA) suggest a stabilization in US oil and gasoline demand. This is most likely the result of lower prices finally altering consumer behavior.
· There are tentative signs of an economic rebound in China, including accelerating growth in bank lending and a bounce in the Purchasing Manager’s Index (PMI), a measure of economic activity.
· According to the latest data from the EIA, US natural gas production appears to have begun falling at the end of 2008. The extraordinarily rapid decline in drilling activity since that time suggests that production declines will continue to accelerate, helping to balance supply and demand.
The good news is over the past two weeks I’ve seen more signs of a tentative improvement. Chief among those is a notable improvement in the contango situation for both West Texas Intermediate and Brent crude oil. I explained contango at some length here, but it’s important enough to warrant an update. The best way to illustrate is with a visual.
(This chart is fairly detailed and can be tough to read. If you have trouble viewing, it press and hold the “CTRL” key and hit the “+” key on your keyboard. Each time you click “+” it will enlarge the text and charts on your screen.)
This chart shows the futures curve for West Texas Intermediate (WTI) crude oil on two dates, Feb. 4, 2009 and Mar. 16, 2009; the green curve is for February, the white for March.
The futures curve is nothing more than a graphical representation of crude oil prices based on the New York Mercantile Exchange (NYMEX) futures contract. There are crude oil futures contracts expiring each month of every year going out several years into the future. This curve simply plots the current trading price of each one of these contracts.
Note that both curves are upward-sloping, a situation known as contango. What that means is the cost of crude oil for delivery today or over the next few months is lower than the price of crude for delivery six months or a year from now.
For example, a glance at the white curve shows that the April 2009 crude oil futures trade at about USD47 a barrel; this is likely the price you see quoted on the news every day. But crude oil for delivery in January 2010 sells for around USD53 a barrel, and looking out to late 2010, crude sells close to USD60.
Both the white and green curves are upward-sloping, or in contango. But the white line–the current futures curve–is far flatter than was the case a month ago. Note just how steep the Feb. 4 futures curve was over its first one to six month segment.
There are two points to note about an extreme contango situation such as we witnessed in early February. First, it typically indicates a situation where there’s a near-term glut of crude oil but the supply/demand balance is expected to tighten significantly in ensuing months.
This was certainly the situation back in early February. US crude oil inventories were building rapidly; weekly inventory statistics released by the EIA consistently indicated larger-than-expected builds in oil inventories throughout January and into early February.
At the time, there was a particularly great concern about the key oil terminal in Cushing, Okla.; check out the chart below.
Cushing is the official delivery point for US-traded oil futures. Traders pay particular attention to the path of inventories at this key hub.
Inventories soared to 35 million barrels, a record level, in February. The terminal at Cushing was nearly filled to capacity. This extreme glut put pressure on near-term crude futures prices–futures expiring over the next few months–back in February.
Note that extreme contango incentives the storage of crude oil. The storage trade is simple. Traders buy oil on the spot market at depressed prices–back in early February crude could be purchase for around USD41. The trader can turn around and sell oil futures expiring six or 12 months in the future. For example, a trader could have sold March 2010 crude futures for USD57 back in early February. If that trader could store the oil for a year, it’s possible to realize a profit equal to the spread between spot and futures prices; in this case, that would be around USD16 a barrel over a one-year period.
This storage trade exacerbates the glut of crude oil in storage and tends to put pressure on prices. Broadly speaking, when the oil market is in extreme contango it tends to be a negative for crude oil prices and related stocks.
The opposite of contango is backwardation, a situation where near-term crude oil prices are higher than long-dated futures. A crude oil market in backwardation suggests a near-term shortage. Such a shortage puts upward pressure on near-month futures contracts. Markets in backwardation tend to be more bullish for crude and related commodities.
While the current futures curve is certainly nowhere near being in backwardation, the contango is less severe than was the case in early February; the oil storage trade is far less attractive than it was a month and a half ago. In addition, the flatter curve reflects the fact that crude oil inventories are beginning to normalize, while gasoline inventories continue to tighten.
And WTI isn’t the only market showing a less steep contango.
This chart depicts the spread between the first- and second-month Dubai crude oil futures contracts. A positive number indicates that the first month crude oil futures are trading higher than the second month futures; a negative number indicates the reverse, the first-month is trading lower than the second-month.
The extreme negative numbers of the past few months would have encouraged crude oil storage and the use of tankers to store crude. Now, with the spread in positive territory again, that’s no longer the case. This indicates a tightening of the supply/demand balance in this market as well.
Another manifestation of the tightening US crude oil market is the fact that the spread between the US benchmark WTI crude and Brent crude has returned to more normal levels.
WTI is a slightly better grade of crude than Brent and has, historically, traded at a higher price; the long-term average premium is around USD1.30 a barrel. But earlier this year WTI was actually trading at a record-wide discount to Brent. At one point the intraday spread touched USD10.
This situation reflected the glut of crude that was apparent in the US, particularly at Cushing. Because WTI is the US oil benchmark, it tends to reflect US supply/demand fundamentals. Brent is the international benchmark and better reflects global fundamentals.
I wrote in the Feb. 4 issue of my expectation that these two benchmarks would eventually revert to a more normal relationship. That’s happened over the past couple weeks. The main driver of that normalization has been WTI, not Brent. The WTI price has rallied sharply to overtake Brent, reflecting an easing of the US oil glut and, quite likely, a slowing in the rate of demand destruction. This, too, is a positive for oil prices.
One aspect of the weekly crude oil inventory reports released by the EIA that’s often ignored is the data on US oil and gasoline demand. The EIA measures demand over a trailing four-week period and compares it to the same period of the prior year. As my chart below shows, at the very least the pace of US oil demand destruction has slowed.
Source: Energy Information Administration
This chart shows a composite of total US demand for refined products and oil. The pace of demand destruction has roughly halved from falling about 8 to 10 percent annualized last fall to closer to 4 to 5 percent so far this year.
US gasoline demand is, in fact, higher on a year-over-year basis; the biggest percentage decline in demand is for jet fuel, likely due to the fact that airlines are cutting capacity and eliminating unprofitable routes.
And the Chinese economy continues to show signs of improvement. In the last TES I looked at official Chinese economic indicators, including the Purchasing Manager’s Index and data on new lending by banks. Even more relevant with respect to commodity prices is data on electricity generation and commodity import demand.
This chart shows the year-over-year change in Chinese electricity production for each month going back to the beginning of 2007. These figures can be skewed from month to month by factors such as weather events or shutdowns of major plants for refueling or maintenance. The important thing is the larger trend.
It’s clear that year-over-year growth in Chinese electricity production was strong for most of 2007 and into the first half of 2008 and then decayed rapidly after midyear. Electricity production actually shrank sharply in the fall. The glimmer of light at the end of the tunnel is that Chinese electricity demand grew again for the first time in months in February. This signals an uptick in manufacturing activity, and probably consumer spending as well.
And we can measure China’s import demand by monitoring global shipments on dry bulk carrier ships. Dry bulk carriers are used to transport cargos such as coal, iron ore and grains.
This chart shows the total number of dry bulk fixtures set each month. This isn’t the total tonnage, but the number of ships chartered.
There’s significant month-to-month variation, due to various factors such as the negotiation of prices for various commodities. However, there was a pronounced and sustained drop in dry bulk fixtures between mid-summer and December. That said, fixtures rebounded in February, hitting levels unseen since June 2008.
The March data (highlighted in red) looks light at first glance, but remember the month is only a little more than half over. If the pace of fixtures continues, March will shape up at least as strong as February. Although data on exactly what these carriers are transporting and where it’s going isn’t always available, it’s fair to say that many of these fixtures are a direct result of a pickup in Chinese commodity import demand.
Each of these factors and data points means little in isolation. But together they establish a simple picture: Declines in global oil supply (production) are beginning to catch up to the decline in global demand.
In other words, the main dynamic driving crude oil since last summer was that a rapidly deteriorating global economy spelled a big percentage decline in oil demand, particularly in the developed world. In the US the pace of decline in demand reached record proportions in the fall.
On the supply front, OPEC responded to falling prices by cutting output, slowly at first and then more aggressively moving in to the final months of 2008. Outside OPEC, most projects would have remained on reasonably solid footing financially until sometime in early November when oil first breached the USD70 level. After that, as oil fell steadily so did the decline in drilling activity and production.
It took some time before the pace of production declines began to match up to the pace of demand destruction. The signals I outline above suggest we’re now at this tipping point. Even better, there are some signs that global oil demand is stabilizing. This sets up the potential for a particularly bullish scenario: The fall in oil supply looks to be accelerating just as demand begins to revive.
Don’t be fooled by the rhetoric out of OPEC last weekend. OPEC essentially decided to leave its production targets unchanged and to enforce existing targets more aggressively. Current estimates are that OPEC compliance is running around 60 percent–producers have, as a whole, only cut about 60 percent as much as they agreed to cut. Iran and Venezuela, facing severe budget constraints, have only complied roughly 33 and 50 percent, respectively.
Meanwhile, Saudi Arabia the United Arab Emirates and Kuwait, among others, have made 100 percent or more of their agreed cuts. Even without additional cuts to the actual production targets, there’s plenty of room for OPEC production to drop further. And data on tanker sailings suggest that oil moving out of the Middle East, destined for the US and Western Europe, continues to plummet. OPEC is definitely cutting production sharply.
The crude price reacted negatively to the OPEC headlines over the weekend, trading USD2 lower in the morning, but it closed Monday’s session higher. This is exactly the sort of reaction I was looking for to get more bullish. Crude oil reacted positively to what looked like bad news, a sign the bad news wasn’t really new and had already been priced into the market.
I’m under no delusion that oil is headed to USD90 or USD100 by summer. After all, OPEC still has plenty of spare capacity right now, probably more than 4 million barrels a day by this June. This production could be brought back online quickly as prices rise back toward the USD70 area. And OPEC is clearly worried about allowing prices to rise too high in the middle of a global recession.
However, I suspect we’ve seen the lows for this cycle and could easily see prices touch the USD60 to USD70 area by mid-summer if these trends persist. This also means energy-levered stocks have likely seen their lows and could experience a significant rally over the next few months.
In short: The signs are still tentative but I’m more bullish on the energy patch and commodity prices than I’ve been in many months. And I’m boosting exposure to crude oil by recommending one of the most oil-levered producers in my coverage universe, Suncor Energy (NYSE: SU).
With 42 years in the region, Suncor is the most experienced player in the Canadian oil sands. The company’s total production was approximately 265 thousand barrels of oil equivalent production per day in 2008. Of that, 86 percent was production from the oil sands, the remaining 15 percent natural gas.
The oil sands are among the few major North American plays with the potential to see actual growth in production in coming years. And Suncor’s strategy has been to be a key participant in that growth; the company approved a nearly CAD21 billion capital spending plan in early 2008 that was designed to more than double its current production to about 550,000 barrels a day by the end of 2012.
But that level of capital spending just isn’t possible with oil prices at less than USD50. In its fourth quarter conference call in late January, Suncor projected its full-year cash costs at CAD33 to CAD38 per barrel. Total costs of production would be higher than that.
Even more importantly, remember that the oil sands business is highly capital intensive. Oil sands are essentially a semi-solid, tar-like form of oil known as bitumen that’s mixed with sand and rock. Bitumen can certainly be refined into useful products like gasoline and jet fuel, but there are many additional steps required.
In the simplest terms, producing oil sands is a combination of mining and refining. For those unfamiliar with the refining industry and exactly how capital intensive it is, check out the Mar. 13 issue of The Energy Letter, where I discuss my recent trip to Chevron’s (NYSE: CVX) Richmond, Calif. refinery. I’ll leave a longer discussion of exactly how oil sands are produced for a future issue; for a bit more color right now, click here.
In order for it to be worthwhile for a company such as Suncor to build out all the equipment and infrastructure necessary to start up a new oil sands project, prices must be high enough to cover cash costs and Suncor’s cost of capital and to produce a decent return on investment. Given just how sensitive the economics of an oil sands project are to costs, producers need to see prices remain relatively high for some time before committing the necessary investment; oil sands projects take at least three to five years to bring online, so if capital is to be invested prices must remain sustainably high.
Bottom line: Depending on the producer, crude oil prices would need to be at or above the USD70 to USD80 range to make major new oil sands production projects economically feasible. This high hurdle tends to make oil sands-focused producers the most leveraged to the fate oil crude oil prices.
This chart illustrates the correlation between WTI crude and five energy stocks. The higher the number, the more closely the stock has been correlated to movements in crude oil over the past five years.
The least correlated stock on my list is independent refiner Valero (NYSE; VLO). This makes sense because refiners don’t make money from rising crude oil prices but from the spread between the price of refined products and crude. Rising crude prices can actually negatively impact refiners.
The integrated oils, Chevron and ExxonMobil (NYSE: XOM), are slightly more correlated to crude prices. Integrated oils are typically the most defensive plays in energy. They also have significant exposure to refining as well as oil and natural gas production.
The most correlated stocks on my chart are the independent producers, Apache (NYSE: APA) and Suncor. Neither has a refining operation to diversify its business. Suncor is particularly exposed thanks to its relatively high costs of production as well as the fact that close to 90 percent of its annual production is oil rather than natural gas.
But all of this is not to say that Suncor is shutting down its operations because oil prices are depressed. The company produced about 230,000 barrels a day from its oil sands assets last year and actually intends to increase that figure to closer to 300,000 this year. That expansion will largely be the result of de-bottlenecking at existing facilities and efficiency gains, not the start up of new projects.
What Suncor has done is to cancel several of the major expansion projects that were designed to meet its target of 550,000 barrels a day of production by 2012. The list of cancelled projects includes a capacity expansion for upgraders–key equipment in refining bitumen into usable products–at its Firebag project and its massive, CAD21 billion Voyageur project.
The firm had originally expected to spend CAD7 billion this year on capital spending, most aimed at moving ahead with these growth projects. In October Suncor cut its spending plans to CAD6 billion, and in January yet again to CAD3 billion.
Of that CAD3 billion, about CAD2 billion is slated for maintenance of existing facilities, another CAD300 million for completing a few projects in later stages of construction, and the balance is to be focused on making the Voyageur project safe for mothballing. Suncor is already about a third of the way complete with Voyageur and has spent upwards of CAD7 billion; this is effectively a sunk investment until oil prices rise to the point where it makes sense to resume construction.
In other words, Suncor is hunkered down to weather the storm of low oil prices. But the company is on a solid footing: It has CAD3.5 billion in unused credit facilities with a large consortium of Canadian banks. And Suncor doesn’t need to rollover any of this financing until 2011. Suncor has adequate liquidity.
And Suncor also made a point of saying that this downturn will actually allow the firm to spend more manpower and cash fixing bottlenecks at existing operations and making improvements that will cut costs. This was difficult to do when the firm was running at full-bore production. Suncor may also benefit from falling costs–the costs of raw materials, labor and other oilfield services should begin to decline as the year moves on to reflect lower oil prices.
Suncor also benefits from a weaker Canadian dollar. Most of its costs are priced in Canadian dollars, and its revenues are primarily in US dollars; oil is priced in US dollars, and the primary end market for its oil would be the United States.
But more important than how Suncor will survive the downturn is what opportunities it will have once the market for oil turns. Specifically, the mothballing of Voyageur and part of Firebag mean that Suncor won’t meet its 550,000-barrels-a-day target by 2012. But Suncor remains one of the only companies in North America with the potential to significantly grow production in coming years. When oil prices do recover, the firm will be in an excellent position to bring new volumes to market and take advantage of rising prices.
I’m also encouraged by the fact that Suncor was extremely adamant in its fourth quarter call that it would be willing to form a joint venture to enter the refining business or on certain projects. However, Suncor said point-blank that it’s not willing to give up any control of actual reserves. This suggests long-term confidence in the value of its properties.
From a tactical perspective, I’m also encouraged by the stabilization in Suncor’s stock over the past few months.
Despite cutting its capital spending plans more than expected and issuing some conservative guidance in late January, Suncor didn’t see a big selloff. And although oil and natural gas prices remained relatively weak from mid-January through the end of February, Suncor held in there. The spike in volume over the past few weeks suggests institutional investors are piling back into Suncor as a potential play on rising oil prices.
The premier play on Canada’s vast oil sands is a new addition to the Wildcatters Portfolio. Buy Suncor Energy under 30.
I’ve made it a habit to admit to admit by bad calls as readily as I discuss my better ideas. Over the past few months I’ve maintained a more bullish stance on natural gas relative to oil prices. My thesis was that natural gas demand would hold up better than oil demand; a cold winter coupled with relatively recession-resistant demand for electricity would keep gas demand high even while oil demand slumped as consumers drove and flew less.
Since the end of August US gas prices are off about 46 percent (based on the 12-month NYMEX strip), while oil prices are off about 57 percent. Since the end of November, however, there’s no contest: Oil is off about 10 percent, but gas is down 30 percent. Although it hasn’t been a disastrous call, focusing on natural gas-levered plays certainly hasn’t helped us much; natural gas stocks have performed in-line, at best, with oil-levered names.
But admitting this error is less important than understanding what exactly I got wrong. In this case, it’s simple: I didn’t expect the evaporation of industrial gas demand to be quite as severe as it’s been over the past several months. Granted, I’ve been relatively bearish on the US economy, but the decline in industrial production has reached unprecedented levels. Check out my chart of US industrial production below for a closer look.
This chart shows the year-over-year change in US industrial production going back to the early 1970s. On this basis the US recession has surpassed the recession of the early ’80s and has reached levels unseen since at least 1974. That ’74 recession is the worst downturn since the Great Depression.
Industrial demand makes up around a third of US gas demand. Despite a big jump in heating demand caused by the cold US winter, a slump in liquefied natural gas (LNG) imports due to high gas prices overseas, and still-strong US electricity demand, gas demand has slumped. Inventories are hardly at extremely glutted levels, but right now they’re some 200 billion cubic feet above expectations.
I underestimated the impact of this industrial slump on the natural gas market, but ultimately the story in the natural gas market is much the same as its is for oil: The accelerating decline in US gas production is beginning to overtake the decline in demand. For this reason, I’m looking for US natural gas prices to roughly double from current prices, climbing above USD7 per million British thermal units by the end of summer.
Here’s a picture of production.
This chart shows the total number of rigs actively drilling for natural gas in the US. I can’t stress enough just how dramatic the decline in the gas-directed rig count has been since August 2008. The decline from more than 1,600 active rigs to less than 900 is the steepest on record.
The effects of this decline in activity are lagged three to four months. At first the US rig count declined only slowly because producers were still profitable at early September gas prices. But the really dramatic rig count decline didn’t begin until the end of November. According to historical norms, this precipitous move is just beginning to hit production.
In addition, wells drilled in August and September might not have been actually hooked up to a pipeline until October or even November; this backlog of wells kept production growing for a few weeks after the rig count began to plummet.
There’s no question we’re now seeing the impact of falling production. Last week the US saw a drawdown of 112 billion cubic feet (bcf) compared to expectations of around 103. And the EIA-914 survey indicates that US natural gas production in December was flat with November, even as production idled in the Gulf of Mexico during Hurricanes Gustav and Ike came back online. If we exclude the bounceback in Gulf gas volumes, US December natural gas was off by more then 0.5 percent.
The next EIA-914 survey is due to be released March 31 and will contain data for January production; I suspect the decline in the gas-directed rig count started to get real traction in January. The rig count influences production with around a three-month lag, so we won’t see the full impact of the massive drop-off in rigs until summer, when the EIA-914 survey begins to reflect data for February and March.
According to the EIA’s most recent Short Term Energy Outlook (STEO), US natural gas consumption is expected to decline by around 1.3 percent in 2009 and rebound weakly in 2010. EIA’s current estimates suggest that US production will be flat this year and fall 0.8 percent next year; however, these projections are highly likely to be revised downward in subsequent reports. The reason is that the decline in the US gas rig count has been far steeper than most analysts had expected.
The decline in the US rig count will probably mean shrinking US production on the order of 4 to 6 percent annualized, if not more. If we take the December decline of 0.5 percent (excluding Gulf production) and annualize it, the decline would be more than 6 percent year-over-year. And I believe the decline will accelerate given the rapid fall in the rig count since that time. Just as with the oil market, that would mean the pace of decline in production is beginning to outstrip the decline in consumption.
Another shorter-term fact weighing on gas markets in recent months is that we’re approaching the end of the winter heating season. If the winter of 2008-09 hadn’t been among the most severe in recent decades, the build-up in inventories would have been far more dramatic. Bitterly cold weather has been a key support for the gas market over the past six to 12 months.
With the end of the heating season, this key support will begin to erode. For example, this week’s storage report, to be released tomorrow, is expected to show a less than 40 bcf decline in inventories. That’s far lower than the 100 bcf-plus declines witnessed over the past several weeks.
But the market is forward-looking, and gas prices are often weak in the final months of heating season because traders discount these effects. This seasonal pattern is already reflected in prices.
I’m not the only one who sees the potential for upside in gas prices over the next six months. Institutional investors are also getting out of the way of this market.
Source: Bloomberg, Commodities Futures Trading Commission
This chart is based on data released on a weekly basis by the Commodities Futures Trading Commission (CFTC). It shows the net position of large speculators in the US natural gas market. A negative number means traders are net short gas; a positive number means they’re net long.
Traders have been net short gas for a long time. However, over the past several months large speculators have been steadily covering their short positions, a signal that these institutional firms believe the downside in gas has already played out.
We have significant exposure to natural gas upside within the TES Portfolio, and I see no need to add to that position at this time. Topping the list of gas plays: XTO Energy (NYSE: XTO), EOG Resources (NYSE: EOG) and Chesapeake Energy 4.5 Percent Preferred D (NYSE: CHK D).
I’ve received a few queries about the latter recommendation from subscribers who’ve experienced difficulties looking it up on brokers’ websites. The problem is that each broker’s website uses a slightly different system for inputting symbols on preferred shares. Some websites might list these shares as CHK-pd while others use the symbol CHK_D. The only way to know for sure is to call your broker and ask; they should be able to look the preferred shares up for you and tell you how to input an order.
Oil Services giant Weatherford International (NYSE: WFT) would be another beneficiary of a recovery in natural gas prices.
If a rally in gas does begin to take hold over the next few weeks, I’ll look to recommend new exposure to this market. Topping my list of potential new additions is land drilling giant Nabors Industries (NYSE: NBR), a stock that was stopped out of the Portfolio earlier this year. I’m also eyeing Ultra Petroleum (NYSE: UPL), an extremely low-cost producer of natural gas in the US. And finally, among the big services firms Halliburton (NYSE: HAL) probably has the most exposure to the US natural gas market.
The Energy Strategist has always been about far more than just the oil and natural gas markets. In the January 21, 2009 issue, I discussed the turn in uranium mining and other nuclear-focused stocks. That group has continued to outperform.
Another group that’s on the move higher again is the agricultural firms and the stocks recommended in my Biofuels Field Bet; I list the full table of picks and my current advice below.
My good friend and colleague George Kleinman recently penned a piece entitled Trade of the Month: A Soy Play for his excellent free e-zine, Commodities Trends. His point: Soybean futures appear to be forming a low as the wave of institutional liquidations that plagued this market last year come to an end. George also highlights the fact that despite what you may have heard to the contrary, global supplies of soybeans are ultra-tight while demand remains strong–US soybean exports remain robust, particularly to China.
You might wonder how I can possibly be writing about soybeans in a newsletter dedicated to energy investments. The answer is simple: Developed countries are using food such as soybeans, corn and palm oil to make biofuels such as ethanol and biodiesel. In many developed countries the use of these biofuels is mandated; governments are essentially pushing demand.
At the same time as developed-world demand for biofuels is growing, demand for food in the developing world is exploding. People in developing countries are gradually eating more total calories per day. But “more calories” IS NOT the primary driver of growing demand; rather, it’s food upgrading. (See TES, Sept. 19, 2007, Down on the Farm.)
Demand for food is rising not because the global population is growing, but because the global population is becoming wealthier. We’ve all heard that Americans and many Europeans are becoming fatter because, quite simply, they’re eating more food–particularly food that’s unhealthy, such as prepared snacks and fatty oils. This trend is nothing new; consumers tend to consume more food and more processed foods and meat as they become wealthier.
Source: Food and Agriculture Organization of the United Nations
This chart uses data provided by the United Nations known as food balance sheets. For each country, these balance sheets detail the type of foods consumers eat in great detail. I’ve used China’s balance sheets going back to 1961 to produce this chart.
To create this chart, I calculated the total number of calories the average Chinese consumer eats per day in a given year. I then calculated what percentage of that total intake came from meat or animal products consumption. So, for example, a figure of 20 percent indicates that roughly a fifth of total calories came from meat in a given year.
The chart clearly illustrates that in China, meat consumption is growing rapidly. Total daily average calorie intake grew nearly 80 percent in China between 1961 and 2003. But meat consumption grew by more than 11 times over the same period.
Thus, while animal products accounted for barely 5 percent of daily consumption as recently as 1970, by 2003 meat was already more than 20 percent of the diet. There remains room for more upside; in the US and Germany, for example, meat accounts for as much as a third of consumption.
This same basic pattern has repeated on multiple occasions throughout history. In poorer countries, consumers derive their daily sustenance mainly from basic grains known as cereals–wheat and rice are two common examples. But as countries become wealthier, meat intake rises, as does consumption of processed foods such as cheese, alcohol and sweets. As you might expect, total daily calorie consumption also rises; the wealth effect on food upgrading is the more powerful trend, however.
You might be asking at this point what this has to do with biofuels. Simply put, it takes eight to 10 pounds of grain and feed to produce one pound of meat. These figures vary depending upon the type of meat produced, but 8-to-1 is a decent rule of thumb.
As meat consumption rises, the effect on grain and feed demand rises at an even faster pace. With literally billions of consumers in the emerging markets now starting to demand more processed, meat-based foods, there’s an ever-expanding wall of demand for products like soybeans, corn and wheat.
From a shorter-term perspective, the US Dept of Agriculture (USDA) released its latest monthly outlook on Mar. 11. The USDA indicated that US soybean stocks are projected to end at 185 million bushels, 25 million bushels lower than the USDA’s most recent estimate. The primary driver of this reduction? “Soybean exports are raised 35 million bushels to 1.185 billion reflecting record sales to China…”
And it’s not just soybeans. The USDA also indicated that corn use for ethanol is accelerating this year because gasoline prices have recovered, making ethanol more attractive as a blending stock.
My point is that agricultural commodity prices are depressed right now, but these products are necessities, not luxuries. Recent data from the USDA certainly indicates that Chinese demand for agricultural products remains robust.
Long-time TES readers are familiar with my “field bet” concept. As is the case with nuclear power, I see biofuels as a multi-year secular growth story in the earliest stages of expansion. More broadly, I see the entire agricultural industry in the midst of a multi-year expansion driven by higher demand for agricultural commodities for both food and fuel.
Instead of just picking one or two highly leveraged plays on biofuels, I recommend casting a much wider net. By buying several biofuel plays of differing risk levels, we can diversify our risk and maximize our chances of hitting a few big winners.
My current Biofuels Field Bet is listed below along with a brief description of each stock and my rationale for adding it to the list. The trick to this field bet isn’t to bet the farm on any one pick. For return calculations, I’ll place 20 percent of a normal position size in each stock. Thus, if you normally put USD10,000 in a Gushers recommendation, I’ll assume a USD2,000 position size.
Here’s my current Biofuels Field Bet.
Source: The Energy Strategist
I’ll leave a discussion of news updates on these picks to a future issue. Here’s a brief rundown of what these companies do.
Mosaic (NYSE: MOS) and Potash (NYSE: POT)–Both firms are major global fertilizer producers. In order to maximize yields farmers must fertilize their crops. This is particularly true for land that’s more marginal in terms of agricultural productivity.
Potash is one of the world’s most important fertilizers; the key mineral is actually mined from the earth. Building and commissioning a new potash mine and production facility takes years, and when demand is strong supplies get tight quickly. These two producers control much of the world’s potash production capacity.
Potash prices have fallen off their highs in recent months along with the prices of most agricultural commodities. But the big producers have idled capacity, and there’s no glut of supply. If I’m right about a rebound in agricultural futures prices, this will likely translate into much higher demand. I consider Potash and Mosaic lower-risk picks and must-owns as far as the Biofuels Field Bet is concerned.
MP Evans (London: MPE, OTC: MPEVF) and Anglo-Eastern Plantations (London: AEP, OTC: AEPLF)–These London-traded stocks both own palm oil plantations in Indonesia and Malaysia.
Palm oil is the most popular edible oil across most of Asia, and it has also become a key feedstock in the production of biodiesel; the world’s largest farms are located in Malaysia and Indonesia. You may also be familiar with palm oil; a brief glance at the wrapper on some candy bars will reveal that it’s often used as an ingredient.
Strong growth in demand for oils and fats in the developed world combined with rising use as a biodiesel feedstock should keep demand strong for palm oil. Both MP Evans Angl-Eastern Plantations are moderate-risk plays and rate buys.
Monsanto (NYSE: MON)–This is the world leader in genetically modified (GM) foods, with at least a two-year lead in terms of new seed development. Monsanto produces seeds for plants that exhibit certain desirable traits such as disease or drought resistance. The new trend is what’s known as “stacked traits,” basically combining multiple favorable traits into a single plant.
The beauty of Monsanto’s business is that its products dramatically increase a farmer’s yield per acre and reduce costs in terms of pesticides, fertilizer and irrigation. Therefore, even with agricultural prices relatively low, farmers have an economic incentive to plant Monsanto seeds. Monsanto is a low-risk play and another core holding.
Sipef (Belgium: SIP)–Sipef owns plantations quite literally all over the world, including Vietnam, Papua New Guinea, Indonesia and the US. It’s a broader play than the two palm oil-focused plantations listed above. Sipef produces bananas and other fruits, palm oil, tea, coffee, rubber and even fresh flowers.
Palm oil is still the most important product for Sipef, accounting for roughly three-quarters of production. The company also recently built a giant storage facility for palm oil to facilitate its export into the fast-growing Asian markets.
All the products that Sipef produces are at the epicenter of demand growth in Asia. As a major producer of palm oil, Sipef has been benefiting from both increased production and rising palm oil prices. Sipef is a buy.
Syngenta (NYSE: SYT)–Syngenta is the global leader in pesticides and herbicides–chemicals sprayed on crops to prevent damage from insects or out-of-control weeds. The company also makes a variety of chemicals used to treat and protect crops from various diseases and fungi.
Although it’s not as advanced as Monsanto’s, Syngenta also has a GM seeds business. Syngenta is a core holding as well.
PowerShares Deutsche Bank Agriculture Fund (AMEX: DBA)–This exchange traded fund (ETF) tracks the performance of a number of different agricultural commodities. Note the ETF’s value is based on the value of the commodity itself, not stocks with exposure to these markets.
PowerShares Deutsche Bank Agriculture Fund is a convenient way to play agricultural commodities in a diversified way.
Novozymes (OTC: NVZMY)–Novozymes is a world leader in the manufacture of enzymes. Enzymes are nothing more than proteins used to catalyze certain chemical reactions. Enzymes are used in the production of ethanol from corn, sugar or any other agricultural product. Novozymes is a world leader in producing enzymes for ethanol production.
A potential growth play for Novozymes is second-generation ethanol. This form of ethanol would be manufactured from agricultural waste or non-cultivated products such as corn husks and a type of prairie grass known as switchgrass. It makes sense to make ethanol from useless products rather than the crops we need for food or as feed for livestock.
But there’s a problem with second-generation ethanol: The technology isn’t ready yet. Although you’ll often hear these technologies hyped, the reality is that second-generation ethanol is technologically possible but extraordinarily expensive.
The reason is that these waste products don’t have the concentrations of sugars and starches needed to efficiently make alcohols. Most realistic estimates suggest commercial applications for second-generation ethanol are at least a decade away.
But one of the keys to making second-generation ethanol feasible will be advanced enzymes to catalyze the process. Novozymes is a leader in this research.
LandKom International (London: LKI)–This higher-risk play has been a major udnerperformer for us over the past year. However, I do think the stock has long-term promise and I’ll retain it in the Portfolio.
Basically, Landkom owns arable farmland in the Ukraine. The Ukraine is a key producer of agricultural commodities for the EU. LandKom is a buy for those with the stomach to handle its higher-risk profile.
Our recommended stop in Italian integrated oil giant Eni (NYSE: E) was triggered earlier this month. The decline in the stock has little to do with company-specific fundamental and a lot to do with broader market weakness.
For the reasons outlined in a Dec. 18, 2008 Flash Alert, I continue to like the stock and am adding it back to the Proven Reserves Portfolio.