Looking For Some Upside
The correction in the energy patch from May to September was vicious at times. But that move culminated in a bout of panic-driven selling in September; since that time, I’ve been adding exposure to select stocks in the coal and services sectors.
I see room for additional upside in both energy commodities and related stocks in the next few months. In this issue, we’ll take another look at the natural gas and oil markets and some of the bullish signs emerging in these groups.
I’ll be taking a particularly in-depth look at the independent exploration and production (E&P) industry. Unfortunately, too many pundits believe that E&Ps are just leveraged bets on oil and gas prices; there are plenty of other factors to consider.
In fact, selectivity in this sector is the key to performance. I’ll be reviewing my favorite plays and introducing a new E&P to the Portfolio.
Finally, it’s always amazing to me how many industry groups are intimately tied in one way or another to the future of energy prices. Railroads are, for example, tied to the coal market; rails are the most-important mode of transport for coal in the US.
Of course, the airlines are also a play on energy; fuel prices are the No. 1 cost center for the airlines. In this issue, we’ll take a closer look at one metal that’s seeing rapidly rising demand because of its use in clean diesel filters–platinum.
In This Issue
Natural gas inventories are still higher than average for this time of year. But supplies have already decreased since the beginning of 2006, and this winter may not be quite as warm as last year. See Natural Gas.
Traditionally, winter is a seasonally strong period for drillers. However, Canadian drillers appear to be having a slow period, while the US drilling market is barely moving either way. See Drilling Activity.
Talks of production cuts from Middle East seemed to have little effect at first as expectations were grim that they would actually go through. But some signs now point to an actual decrease in supply that will affect pricing. See Crude Oil.
The E&P industry is among the simplest to understand in the oil and gas business. I provide a list of 33 US and Canadian E&P companies I follow and include breakout reviews of two favorite E&Ps, as well as a new Wildcatters Portfolio addition. See Exploration And Production.
Although often more highly associated with jewelry, platinum plays a major part in the diesel fuel world as well. I’m adding a new Gushers Portfolio holding to capitalize on the one of the fastest-growing car industries. See Going Platinum.
In this issue, I’m recommending or reiterating my recommendation on the following stocks:
I’m also recommending avoiding the following stocks:
Natural Gas
In last week’s issue of The Energy Letter, Signs Of Strength, I discussed the US natural gas market at some length. To summarize, the prime obstacle to upside in natural gas prices remains excess gas in storage in the US market.
This has been the nagging problem for natural gas since last winter, when far-warmer-than-average temperatures prompted a buildup in inventories. It also accounts for the violent swings in the commodity prompted by every change in the near-term weather forecast. The chart below offers the typical presentation of US natural gas inventories.
Source: US Energy Information Administration
A few points are worth noting about this chart. First, natural gas inventories are still higher than average for this time of year. In fact, you can clearly see that since 2001, inventories of gas have never been higher at this time of year. Short-term gas supply remains excessive.
But also note that gas in storage peaked a bit earlier this year than in the other years covered on this chart. Moreover, gas in storage is starting to fall toward levels that would be considered more normal; the 2006 line on this chart is starting to move closer to the other lines. Presenting the very same data in a slightly different manner yields the chart below.
Source: US Energy Information Administration
Basically, this chart compares current gas inventories to the five-year average. Positive numbers indicate how far above average inventories are; levels less than zero would, of course, suggest inventories of gas that are lower than average.
Peak excess inventories of natural gas totaled more than 600 billion cubic feet (bcf) in late spring and early summer. Although inventories are still above average, they haven’t been this close to average at any other time this year. At the very beginning of 2006, inventories of gas stood at around 200 bcf above normal; now inventories stand at just 185 bcf. That’s equivalent to just three days of US supply.
My point in all of this is to put gas inventory data in perspective. I hear this excess gas supply argument all over the media nowadays; the simple fact is that it’s not as bad as some are making it out to be. And the gas inventory picture has improved markedly since last summer.
A warm winter would leave the US with excess supplies of gas once again in 2007. One of the reasons gas prices dipped so precipitously in September was that the National Oceanographic and Atmospheric Association (NOAA) began to forecast a warmer-than-normal winter again this year. But, as I explained in the October 18 issue of TES, NOAA also was careful to state that this winter would be much cooler than last year.
Moreover, the “warm winter” thesis has already become conventional wisdom in the gas market. If NOAA gets it wrong and we get just an “average” winter heating season, I see big upside for gas.
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Drilling Activity
For much of the year, strong North American drilling activity presented a paradox. After all, with supplies of gas higher than average and prices falling for much of the year, it’s only logical to suspect that there would be a meaningful slowdown or at least a moderation in drilling activity.
This is the main reason I’ve been recommending avoiding the US-leveraged gas services stocks and land drillers for most of this year. But check out this chart of the current rig count.
Source: Bloomberg, Baker Hughes
This is the US land rig count—the total number of rigs actively drilling for oil and gas on land in the US. As you can see, the rig count has dipped slightly from its high in September. But that dip is almost imperceptible.
It’s not unusual to see the rig count pause like this before moving higher again. Bottom line: There doesn’t look to be much, if any, slowdown in US land drilling activity. But check out the Canadian rig count in the chart below.
Source: Bloomberg
There’s an obvious seasonality in the Canadian rig count; the rig count hits a low in the spring, then spikes higher through the summer, fall and winter.
Last year, the rig count in Canada spiked particularly high in the winter months. This was likely a response to the spike in natural gas prices in the wake of the vicious US hurricane season. The rig count then dropped off in March and April–fairly typical seasonal action.
What’s interesting is what’s happened since April. Specifically, the rig count never rose to levels as high as it has in past years. And rather than seeing continuing strength in Canadian rig counts as we head into winter, the active rig count appears to be continuing to slide lower.
My take is that these data are consistent with what we’ve heard from several services firms in recent months. The North American oil services market remains very strong with the exception of a few minor pockets of weakness. Those weak spots include coal-bed methane (CBM) and Canadian shallow gas.
CBM wells have an unusual production profile in that there’s initially a large rush of gas from these wells, followed by a particularly sharp production drop-off. As I outlined in the November 1 issue of TES, Earnings Bonanza, Schlumberger felt that some companies were holding off on producing CBM wells to try to “time” that initial rush of gas and take advantage of more favorable prices.
Another weak spot that Schlumberger highlighted was Canadian shallow gas. Canadian shallow gas has a relatively high cost of production; when natural gas prices are under $7 or so, shallow gas is marginally profitable to produce at best.
And with labor, raw materials and services costs more expensive than ever, this has further cut into the profitability of exploiting shallow-gas reserves. The weaker-than-normal Canadian rig count suggests that there’s been a significant moderation in Canadian shallow-gas activity this year.
I would note two points about all these data. First, North American drilling activity remains very strong and there’s been, at best, only a minor moderation in drilling demand. That bodes well for most services and equipment firms–companies that sell the products and services needed for all this drilling activity.
Second, with drilling activity still strong overall, it’s interesting that US gas inventories are moderating. This shoots holes in the thesis of those who were projecting that all this drilling would result in rapid production growth, ramping oversupply and collapsing gas prices.
This certainly doesn’t appear to be the case. It’s also worth pointing out that internationally, there’s been no slowdown in oil and gas exploration and drilling activity at all.
To play the still-strong global drilling and exploration markets, the best bets are oil and gas services companies. My favorites in the oil services and equipment business right now are, in no particular order, Schlumberger, Tenaris and Petroleum Geo-Services.
I’ve highlighted both Schlumberger and Petroleum Geo in recent issues of TES, including the November 1 issue. See that issue for my detailed rationale for owning these stocks.
Tenaris makes what are known as oil country tubular goods (OCTG). The company sells specialized pipes to oil and gas production companies. Once a well is drilled and completed, these pipes are the conduit through which hydrocarbons flow to the surface. Because of the high geologic pressures and temperatures that are commonplace in the oil and gas business, OCTG’s are manufactured to certain specifications set by the American Petroleum Institute.
Tenaris is the largest global manufacturer of tubular goods. The company has been highly acquisitive over the years, buying up local manufacturers all over the world.
By acquiring local manufacturers, Tenaris ensures that it’s located close to its key customers. Because pipe is heavy and bulky to transport, proximity to its customer base is key, allowing shorter lead times and faster service.
The company’s most-recent major acquisition was US-based Maverick Tube, a deal just completed in October. Although the US certainly isn’t the world’s largest producer of oil and gas, it is an extraordinarily intensive drilling market.
To produce more hydrocarbons out of America’s mature reservoirs requires continually drilling more wells. That’s why the US has, by far, the largest active rig count of any country on Earth. Drilling new wells requires laying new pipe. Maverick gives Tenaris solid access to the US market.
And not all OCTG are just commodity goods. Tenaris specializes in advanced seamless pipes. These OCTG pipes don’t have the welded seam that older pipes typically had.
This makes such pipes stronger and capable of withstanding higher heat and pressure. Drilling unconventional oil and gas wells and deepwater wells requires the use of these more-advanced pipes.
As outlined before in TES, deepwater and unconventional reserves are becoming the focus of a great deal of exploration and drilling activity because traditionally easy-to-produce onshore reserves are rapidly maturing. This trend bodes well for Tenaris; the stock remains a buy in the Wildcatters Portfolio.
Despite the relatively shallow decline in North American drilling activity, I continue to recommend avoiding stocks overly leveraged to the American market. This is particularly the case with companies overleveraged to commodity-type businesses.
For example, Patterson-UTI is a land-based contract driller; the company leases out land rigs to producers for a fee known as a day-rate. Patterson’s business is almost entirely US-based, and the company mainly owns relatively low-tech rigs. These rigs aren’t appropriate for drilling particularly deep wells.
Attracted to the high day-rates available in the US market, a flood of new commodity-type land rigs hit the US market in recent years. Continued strong activity has held day-rates aloft; even a minor slowdown in drilling activity could rapidly sour the business.
The same picture is true of companies leveraged to the pressure-pumping business. Recall that oil and gas exist underground in the pores, cracks and crevices of rocks, not in giant underground pools or caves. In some reservoirs, those pores aren’t well connected, making it difficult to produce the oil or gas; these reservoirs are poorly permeable.
To solve that problem, producers pump a gel-like liquid into the ground to crack the reservoir rock through a process called fracturing, creating channels through which the oil can flow to the well bore. Inside this gel-like liquid are small particles known as proppant. Proppant gets pushed into the cracks and crevices produced by the fracturing liquid; once the pressure is removed, these particles literally prop open the channels. This technique improves the permeability of reservoirs.
I suspect demand for pressure pumping will remain reasonably strong, given the importance of unconventional gas reservoirs that typically require pressure pumping; the problem is supply.
A record amount of pressure-pumping capacity has been built in the North American market. All that extra capacity will eventually start to weigh on pricing power. This is particularly true if drilling activity does moderate even slightly.
Earlier this year, I recommended a profitable short in BJ Services. Although it’s not a good time to short this stock again, I’d avoid BJ for now.
Another example of a vulnerable pressure-pumping focused services firm is Canada’s Calfrac. As the chart below illustrates, this stock has been particularly weak as of late.
Source: Bloomberg
As noted above, the weakness in Canadian drilling activity has been far more pronounced than in the US. Given Calfrac’s exposure to that market and to shallow-gas drilling, I suspect that’s why the stock is continuing to see so much weakness now. I recommend avoiding Calfrac right now.
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Crude Oil
I sent out a flash alert late last week discussing the implications of weakening very large crude carrier (VLCC) tanker rates in what’s normally a seasonally strong time of the year.
I suspect that Middle Eastern oil shipments are falling as a direct result of the Organization of Petroleum Exporting Countries (OPEC) output cuts announced during the past few months. Recall that when OPEC announced its production cuts, the cuts were widely derided as meaningless. The OPEC member states were all expected to “cheat” and produce more than allowed.
The weak fourth quarter VLCC tanker market suggests that’s absolutely not the case. We now have direct evidence that oil shipments from the Middle East are down. This is bullish for oil because it suggests lower import supplies.
But it’s not just tanker rates that should lead us to the conclusion that production cuts are having an effect on supply. Check out the latest oil import statistics from the American Petroleum Institute (API) pictured in the chart below.
Source: Bloomberg, API
The API import data is highly volatile from week to week; however, there’s an obvious spike to the downside in crude oil imports lately. Some of this could be random noise, but I suspect it’s also a result of lower shipments from the Middle East.
At any rate, despite all the talk of OPEC cheating on production cuts or the concept that OPEC is just trying to talk the oil market higher, there are concrete signs of falling crude oil trade activity. Bottom line: Falling crude oil supplies will support crude oil prices.
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Exploration And Production
Services and equipment stocks are one way to play the improvement in fundamental conditions for oil and natural gas. Another group that will benefit handsomely is the E&P industry. Just as with services, selectivity is paramount.
The E&P industry is among the simplest to understand in the oil and gas business: These companies look for, develop, produce and sell hydrocarbons. The type of reserves exploited by E&P firms differs widely between companies. Some of the largest independent E&Ps are targeting complex deepwater reserves, massive international projects and unconventional resources like the oil sands.
These larger E&Ps have come to resemble the large, integrated oil companies like ExxonMobil (NYSE: XOM) and Chevron (NYSE: CVX). And, of course, there are literally hundreds of smaller E&P’s operating worldwide, some targeting production from a single field or region.
Earnings for services and equipment firms are not directly tied to the price of natural gas and crude oil. That’s because services firms don’t product or sell any oil or gas. Instead, these firms are levered to oilfield activity–the more E&P activity going on globally, the greater the opportunity for the services companies.
In recent years, as oil producers have stepped up their exploration E&P activities, the services firms have benefited royally. So, too, have the equipment firms, selling valves, drill bits and pipe required for any drilling project.
For the services firms, the only link between profitability and hydrocarbon prices is indirect; higher commodity prices tend to encourage more E&P activity. But this link is tenuous.
For example, this year natural gas prices in the US declined sharply with only a minor impact on activity levels. When oil prices declined from $80 to under $60, there was no discernable change in drilling activity, demand for services or capital spending plans, particularly in international markets.
And because international oil and gas development projects tend to be large-scale, multi-year deals, exploration and development activity internationally is less closely tied to commodity prices than the small-scale projects that are so important in North America. Therefore, whether a services firm concentrates globally or locally has a major bearing on its leverage to commodity prices.
In contrast, the E&P business is intimately tied to the prices of oil and natural gas. This should be self-evident: if oil prices rise, then companies can sell their product for more money, hence earning higher profits.
Of course, effectively hedging future production in the futures markets means that E&P firms can lock in favorable prices. Hedging activity can protect E&Ps from temporary lulls in pricing. But at some point, no matter how well a company has hedged itself, a decline in hydrocarbon prices would have an impact on E&P profitability.
Although this distinction may seem obvious, many assume that all companies in the oil and gas business are simply levered to oil and gas prices. That’s just not the case.
And even E&P firms aren’t totally dependant on rising oil prices to keep their profits rolling; there are other factors at play that need careful consideration. Among the most important: production growth.
In the most-extreme case, an E&P firm with no production growth is totally dependent on the commodity markets for profits. Therefore, a 20 percent rise in oil prices would lead to a 20 percent rise in profits, assuming costs are stagnant.
But companies that grow their production over time have an advantage: Rising production can help offset the effects of falling commodity prices. By producing and selling more oil, a company can increase its earnings without depending totally on rising oil prices.
When hydrocarbon prices are rising, E&P firms with solid production growth benefit from a powerful dual trend: They’re able to bring more product to market in a favorable pricing environment. You can’t evaluate the E&P business by simply making a call on the future direction of oil and natural gas prices; just as with any other sub-industry in the energy business, E&P companies must be evaluated on a case-by-case basis.
For a more dramatic example of the importance of production growth and selectivity, check out the chart below.
Source: Bloomberg, The Energy Strategist
To make this chart, I examined the S&P Supercomposite E&P index–an index containing more than 20 US-based E&P companies of all sizes. I first threw out any that have been in operation for less than five years and sorted the remainder by their annualized production growth over the past five years.
After ranking the stocks, I selected the four firms with the best production growth over the past five years and the four with the worst production growth history. I created equal-weighted indexes out of these two groups of stocks, comparing the performance of my “Best” and “Worst” indexes with that of the S&P Supercomposite Index since Dec. 1, 2000.
These indexes don’t include dividends; this is of minor importance because most E&Ps in the index pay few, if any, dividends.
Note that my index of the “worst” E&Ps returned about 130 percent over the period in question. Although that may not seem too bad, it isn’t great when compared to the 205 percent gain in the Supercomposite index over the same time frame. Even more impressive, my “best” index jumped 791 percent; that’s a full six times the return from the “worst” index.
For comparison, the price of oil is up by roughly 140 percent since December 2000. Natural gas prices are actually down over the same time frame, but that’s an unfair comparison; December 2000 marked the height of major price spike for gas because of unusually cool weather nationwide and a series power crisis in California. If we look at average gas prices for 2000, the price of gas is up more than 50 percent since that year.
My point in highlighting all this is that E&P firms with the ability to grow production have been historically able to outperform slower-growing E&P companies and the prices of oil and natural gas. Such firms aren’t completely beholden to the price of oil and gas. Don’t assume that buying or selling E&P stocks involves simply making a broader call on the fortunes of oil and gas prices.
It’s also important to determine how E&P firms are generating their production growth. In the past, E&P firms often grew production via acquisitions; by purchasing smaller firms with attractive reserves, E&Ps can generate production growth without taking on the expense and risk of new drilling and exploration activity. That strategy works well when it’s relatively inexpensive to make acquisitions, such as when commodity prices are weak and smaller E&Ps are struggling to stay profitable.
Nowadays, however, acquisitions are hardly cheap. With oil and natural gas prices sitting at attractive levels and drilling activity strong, companies with attractive reserves and growth prospects are extraordinarily valuable. The cost of acquiring such firms has risen dramatically over the past five years.
Moreover, there’s already been a great deal of consolidation in the US and Canada during the past two decades. That means there are simply fewer “potential” targets for consolidation.
Because of the expense involved with undertaking a major acquisition, organic growth is of paramount importance. Companies with the ability to grow production simply by drilling more extensively on existing properties or exploring new formations in and around existing fields are in the catbird’s seat. Such firms have a chance to growth their production in an environment of high commodity prices. It’s these E&P firms that have the best shot at outperforming.
Meanwhile, E&Ps with stagnant organic growth are just commodity proxies; they’re likely to be particularly vulnerable to any swings in crude oil and natural gas prices. For such firms, the only prospect for growth is a rise in the price of the commodities they sell.
Another important consideration is, of course, a company’s cost structure. As I highlighted at great length above, Canadian shallow-gas drilling activity has fallen off severely this year; the reason activity has declined so much is that this is an expensive-to-produce resource. With gas prices falling sharply earlier this fall, some projects were simply no longer economical.
In addition, the cost of exploring for and developing reserves is also rising. One of the reasons that I’ve been so bullish on the services firms is that they currently have excellent pricing power; the cost of seismic services, pressure pumping, hiring rigs and just about any other service you can imagine is rising rapidly. Although this is excellent news for the drilling and services companies, it all spells rising costs for the E&Ps.
Another major cost center is labor. During the long depression in the oil and gas sector from the early 1980s to the late ’90s, it was tough for the industry to attract new talent. Many US universities stopped even offering courses in oil and gas engineering and geology.
The result: There’s a marked shortage of well-trained, experienced workers in the field. The few experts out there are in high demand and have seen their salaries shoot through the roof in the past few years.
To evaluate an E&P’s cost structure, I look at three different cost metrics. The first is what’s known as a lifting cost–the operating costs of producing oil or natural gas from a well. It’s calculated by dividing total production costs by oil and gas production for the year and is normally quoted in terms of dollars per barrel of oil equivalent production ($/BOE).
Some resources, such as Canadian shallow gas, carry higher production costs and are, therefore, more vulnerable to swings in hydrocarbon prices. This will show up in the form of higher lifting costs.
Another cost metric to watch is acquisition costs. This can be calculated by dividing total property acquisition costs (including buying drilling rights and buying other E&Ps) by the total purchases of reserves for the year.
This cost metric offers a good idea how expensive it is for particular a E&P to grow by purchasing reserves. Typically, this metric is also quoted in terms of dollars per BOE.
And finally, there’s the finding and development cost. This is basically the cost of adding reserves “through the drill bit”–actually going out and looking for new reserves of oil and gas.
In the table below, I list 33 of the US and Canadian E&P companies I follow. I’ve also included five-year annualized production growth and cost statistics for each E&P.
Source: Bloomberg, The Energy Strategist
I already recommend EOG Resources in the Wildcatters Portfolio. On a trailing five-year basis, EOG doesn’t have the fastest production growth of the E&Ps in my table.
However, that’s been changing, and the company is now targeting annualized production growth of about 10 percent. Close to 85 percent of the company’s annual production is natural gas.
The key to EOG’s future growth is its position in one of the US’s most-prolific gas plays, the Barnett Shale in Texas. With leases and drilling rights covering more than half a million acres, EOG is among the largest producers in the region.
The Barnett Shale is an unconventional gas reserve; it can’t be produced economically using simple traditional drilling methods. Specifically, the Barnett Shale lacks permeability so gas won’t naturally flow into wells.
To improve permeability, producers perform fracturing. Reservoirs of gas like the Barnett Shale that lack permeability and must be produced in this manner are known as tight gas plays.
The beauty of the Barnett Shale is that once wells are fractured, they’re extremely prolific. Even better, wells drilled in the region are long-lived. Specifically, shale wells tend to have very steep initial production declines; immediately after the well is drilled, it produces at an extremely high rate but production starts falling off soon thereafter.
However, after the initial production decline, shale wells tend to produce at a near-constant rate for years. That steady, predictable production rate is highly attractive for producers.
EOG’s strong position in the Barnett Shale means it’s likely to be able to meet its production growth targets without making large acquisitions. The company estimates its total reserves in the region at between 4.6 and 6.7 trillion cubic feet of gas.
EOG’s management has stated it intends to drill a total of nearly 2,500 wells in 2007, the majority in the Barnett Shale area. In total, the company has identified about 15,000 potential drilling locations.
EOG has plenty of growth potential simply by drilling on sites it’s identified on properties it already owns. As noted above, organic growth is desirable in this market because acquisitions have become extraordinarily expensive; companies that rely too heavily on acquisitions for growth will find their costs rise dramatically in the next few years.
For most of its history, EOG has focused on tight gas reserves. Therefore, EOG has a great deal of experience and know-how when it comes to identifying and producing such reserves. The Barnett Shale certainly isn’t the only major tight gas deposit in the US; EOG has built up considerable acreage in promising shale play regions all over the US and Canada.
EOG is careful not to reveal many of the locations where it’s buying up acreage because the company doesn’t wish to tip its hand to the competition. In many cases, EOG has been able to move into a promising new region and buy up property on the cheap before other competitors have a chance to move in and drive up prices. EOG will see considerable production growth from some of these promising new plays in the future.
Finally, it’s worth noting that EOG has been taking steps in recent quarters to cut its production costs on the Barnett Shale. The company has, for example, started using rigs that are specially customized for drilling tight gas deposits. By using these rigs, EOG has significantly cut down the amount of time it needs to drill a well.
In addition, EOG has experimented with optimizing how it performs fracturing work. This, too, has boosted efficiency and the speed with which EOG can drill new wells.
With plenty of room for organic production growth and some of the lowest overall cost metrics in the E&P business, EOG rates a buy.
Another US-based E&P that holds promise is XTO Energy. The company has grown production rapidly in the past five years; in fact, it has one of the fastest production growth rates of any US E&P. Like EOG, XTO primarily focuses on natural gas, although it’s boosted its oil output significantly in recent years and has actively purchased oil-producing properties.
XTO historically has grown through a combination of organic growth and acquisitions. On the organic growth front, XTO owns reserves in the Barnett Shale and in the Rockies. Like the Barnett Shale, the Rockies are a hot, nonconventional tight gas play. The company has identified several thousand potential drill sites; XTO has plenty of potential to grow production from its existing properties.
Unlike EOG, XTO does hedge some of its gas and oil production. In particular, the company has hedged close to 40 percent of its 2007 gas production at prices north of $10 per million British Thermal Units, a level significantly above current futures strip prices. These attractive hedges are one reason the stock has outperformed EOG this year.
XTO also has an attractive acquisition model. Basically, the company buys mature oil and gas properties with well-established reserves and production. Because these properties are already developed, XTO doesn’t take on any exploration risk. XTO then invests significant capital to exploit these reserves more effectively; the company is essentially squeezing more oil and gas out of these mature properties.
Although acquiring proven reserves in this manner has become more expensive in recent years, XTO has a history of making the strategy work and the company’s overall costs haven’t risen a great deal in the past few quarters. Management is targeting overall production growth in the low to mid teens; that’s considerably higher than average for US-based E&Ps.
I’m adding XTO to the Wildcatters Portfolio.
As it’s not a US or Canadian E&P company, I didn’t list Wildcatter BG Group (NYSE: BRG) in my table. However, the stock remains one of my favorite international E&Ps.
I like BG Group for a number of reasons. First and foremost, the company has some of the world’s most-attractive E&P assets; production is about 70 percent weighted in favor of natural gas, although the company’s oil assets are also attractive.
BG gets a little less than half its production from the UK’s North Sea gas fields. That gas is sold directly into Britain at attractive prices. UK gas prices are attractive because demand is high (due to new power plant construction), but supplies are diminishing as domestic gas fields are no longer sufficient to meet Britain’s growing needs. This is one highly profitable market for BG.
Outside Europe, BG is one of the most-interesting plays on liquefied natural gas (LNG). The company has gas fields in Egypt, Kazakhstan, Bolivia and Brazil. These assets are highly attractive because of their low production costs and large projected growth in production.
Because these are fairly immature fields, gas production can ramp up quickly. In fact, BG Group has some of the fastest gas-production growth of any major global E&P company. In 2001, the company produced 99 million BOE; last year, production was north of 500 million BOE.
Many of the company’s fields are so-called stranded gas fields, located miles away from existing pipeline infrastructure. But by liquefying the gas, BG can produce these fields and then ship the gas in the form of LNG to distant markets for sale at current sky-high prices.
BG is a key player in US LNG, a market that’s set to grow rapidly in coming years. The company has a LNG re-gasification terminal near Lake Charles, La., that can handle a daily capacity of 1.8 bcf of gas per day.
On the cost front, BG’s international reserves are extraordinarily cheap to produce. Unlike most US fields, BG’s international reserves are relatively immature; they produce at very high rates. The company’s lifting costs are around $3.60 per BOE, and finding and development costs around $9. BG Group remains a buy in Wildcatters.
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Going Platinum
My final recommendation this week will likely seem odd to TES subscribers: I’m adding a platinum mining company to the Gushers Portfolio. Like the railroads and airlines I’ve recommended, platinum may seem at first blush to have absolutely nothing to do with energy; in fact, platinum is a crucial commodity that’s intimately tied to the future of clean diesel fuel.
As I’ve highlighted before in this journal, diesel fuel is a fast-growing fuel worldwide. Diesel-powered cars get as much as 40 percent more miles per gallon compared to similar-sized gasoline engines. Moreover, with the advent of turbo direct injection, diesel cars actually offer performance that’s comparable to or better than equivalent gasoline engines.
Because of this fuel efficiency, diesel is picking up market share all over the world. In 2006, diesel cars accounted for more than half of the European car market; that’s the first time diesel has been more important than gasoline in Europe.
And diesel is also becoming a key fuel in fast-growing Asian markets; in 2004 alone, diesel demand in China soared more than 350,000 barrels per day. Longer term, China’s diesel demand should grow between 100,000 and 200,000 barrels per day every year. Overall, growing demand in the European Union, US and Asia represents as much as 650,000 barrels per day in annualized growth in demand for diesel fuel.
Then, of course, there’s the US. Diesel has always had a less-than-stellar reputation in the American market. That’s partly because early diesel cars sold in the US market weren’t of the best quality.
Early models were plagued by poor performance, particularly in cold weather conditions. That turned off an entire generation of Americans to diesel fuel. But diesel is predicted to make somewhat of a comeback; the US Dept of Energy believes that diesel could account for 8 percent of the US car market in 2030, up from around 2 percent today.
And diesel has always been the fuel of choice for trucks and trains in all markets. This is likely to remain the case.
But there’s a problem with the increased use of diesel fuel: Diesel produces a good deal of pollution. Pollutants emitted from diesel engines include sulphur dioxide, nitrous oxides and particulate matter (basically soot).
Particulate matter is particularly troubling for diesel cars. In China, burning diesel fuel is one of the main culprits for the major Chinese urban pollution problem. The Chinese government has expressed interest in controlling the problem because it’s actually impacting growth potential.
Most governments are tightening environmental regulations for diesel fuel. This includes producing fuel with ultra-low sulphur content and imposing limits and regulations covering emissions from diesel-powered vehicles. This isn’t just a developed market story; China and India are also cracking down on diesel pollution.
One of the offshoots of this environmental regulation is that diesel-powered cars and trucks will need to be fitted with special filters that cut down on emissions of sulphur and nitrous oxides and particulate matter. The key component of diesel filters: platinum.
If you’re like most people, when you think of platinum, jewelry is probably the first product that springs to mind. But platinum jewelry accounts for only about a quarter of global platinum consumption.
The autocatalyst market is far more important: More than half the platinum consumed globally goes into automobile and truck filters. It’s far and away the most-important and fastest-growing use for the metal.
Because Europe is now the world’s largest diesel market, demand for platinum has been soaring there. Check out the chart below for a closer look.
Source: Johnson Matthey Platinum 2006 Review
Europe now accounts for 37 percent of global platinum demand. Demand in Europe for platinum as an autocatalyst has grown from 500,000 ounces in 1997 to more than 2.25 million this year.
But Europe isn’t the whole story. In North America, demand for platinum as an autocatalyst grew 130,000 ounces this year to total nearly 1 million ounces and emerging markets sucked down 650,000 ounces up from around 250,000 a decade ago. Demand is projected to continue accelerating as new tighter environmental regulations are phased in.
Of course, as with any commodity, there are two sides to the platinum story: demand and supply. And when it comes to platinum supply, South Africa reigns supreme.
The country accounts for close to 80 percent of global platinum supplies. South Africa is also the only nation globally that’s been able to significantly boost production in recent years. In other words, it’s a crucial piece of the global diesel market.
Although the supply-and-demand balance in the platinum market is improving, the market still faces a deficit and is likely to remain in deficit again in 2007. In other words, demand for platinum exceeds available supply. Check out the chart of platinum demand and supply below.
Source: Johnson Matthey Platinum 2006 Review
With demand for platinum rising rapidly, mine production will have to rise even faster to keep up with the demand. Most of the additional supply will come from South Africa’s prolific mines. This tight supply-and-demand balance is behind platinum’s big rally during past few years. Check out the chart below for a look at platinum spot prices.
Source: Bloomberg
The world’s largest platinum producer is South Africa’s Anglo Platinum, sometimes called simply Amplats (Johannesburg: AMS, London: ANP; OTC: AGPPY). This company alone produces 40 percent of the world’s platinum–close to 2.5 million ounces annually from mines located mainly in South Africa. The company is 75 percent owned by Anglo American but is traded separately.
Amplats is certainly benefiting from the bull market in platinum as it’s one of the only companies in the world with the ability to actually grow supplies of platinum to meet rising demands. Subscribers looking for a big cap play on platinum should definitely consider buying Amplats.
However, I’m adding a far-riskier and more-leveraged play to the Gushers Portfolio this issue—Platinum Group Metals.
Platinum Group owns a platinum reserve located adjacent to Amplats Bushveld mining complex, one of the world’s most-prolific platinum mines. It’s still an exploration story; Platinum Group isn’t likely to start producing platinum any time soon. However, what gives me confidence is the fact that the company is part of a joint venture to produce its mine in the Bushveld area.
The other major partner in the mining operation is none other than Anglo Platinum itself. Given just how close Platinum Group’s mine is to Amplats’ own operation, one can only assume that Amplats is well aware of the geology and potential for this mine. The fact that they’ve invested in the project suggests that it holds promise.
Please keep in mind that Platinum Group Metals is a very small company, and this is a highly speculative and risky stock to own. I’d recommend keeping your position size relatively small in this stock.
The advantage of buying Platinum Group over Amplats is that it also has much higher upside potential; speculative mining plays can double or triple in the blink of an eye if they’re reserves pan out. Platinum Group Metals is added to the Gushers Portfolio.
I see room for additional upside in both energy commodities and related stocks in the next few months. In this issue, we’ll take another look at the natural gas and oil markets and some of the bullish signs emerging in these groups.
I’ll be taking a particularly in-depth look at the independent exploration and production (E&P) industry. Unfortunately, too many pundits believe that E&Ps are just leveraged bets on oil and gas prices; there are plenty of other factors to consider.
In fact, selectivity in this sector is the key to performance. I’ll be reviewing my favorite plays and introducing a new E&P to the Portfolio.
Finally, it’s always amazing to me how many industry groups are intimately tied in one way or another to the future of energy prices. Railroads are, for example, tied to the coal market; rails are the most-important mode of transport for coal in the US.
Of course, the airlines are also a play on energy; fuel prices are the No. 1 cost center for the airlines. In this issue, we’ll take a closer look at one metal that’s seeing rapidly rising demand because of its use in clean diesel filters–platinum.
In This Issue
Natural gas inventories are still higher than average for this time of year. But supplies have already decreased since the beginning of 2006, and this winter may not be quite as warm as last year. See Natural Gas.
Traditionally, winter is a seasonally strong period for drillers. However, Canadian drillers appear to be having a slow period, while the US drilling market is barely moving either way. See Drilling Activity.
Talks of production cuts from Middle East seemed to have little effect at first as expectations were grim that they would actually go through. But some signs now point to an actual decrease in supply that will affect pricing. See Crude Oil.
The E&P industry is among the simplest to understand in the oil and gas business. I provide a list of 33 US and Canadian E&P companies I follow and include breakout reviews of two favorite E&Ps, as well as a new Wildcatters Portfolio addition. See Exploration And Production.
Although often more highly associated with jewelry, platinum plays a major part in the diesel fuel world as well. I’m adding a new Gushers Portfolio holding to capitalize on the one of the fastest-growing car industries. See Going Platinum.
In this issue, I’m recommending or reiterating my recommendation on the following stocks:
- BG Group (NYSE: BRG)
- EOG Resources (NYSE: EOG)
- Petroleum Geo-Services (NYSE: PGS)
- Platinum Group Metals (TSX: PTM; OTC: PTMQF)
- Schlumberger (NYSE: SLB)
- Tenaris (NYSE: TS)
- XTO Energy (NYSE: XTO)
I’m also recommending avoiding the following stocks:
- BJ Services (NYSE: BJS)
- Calfrac (TSX: CFW)
- Patterson-UTI (NSDQ: PTEN)
Natural Gas
In last week’s issue of The Energy Letter, Signs Of Strength, I discussed the US natural gas market at some length. To summarize, the prime obstacle to upside in natural gas prices remains excess gas in storage in the US market.
This has been the nagging problem for natural gas since last winter, when far-warmer-than-average temperatures prompted a buildup in inventories. It also accounts for the violent swings in the commodity prompted by every change in the near-term weather forecast. The chart below offers the typical presentation of US natural gas inventories.
Source: US Energy Information Administration
A few points are worth noting about this chart. First, natural gas inventories are still higher than average for this time of year. In fact, you can clearly see that since 2001, inventories of gas have never been higher at this time of year. Short-term gas supply remains excessive.
But also note that gas in storage peaked a bit earlier this year than in the other years covered on this chart. Moreover, gas in storage is starting to fall toward levels that would be considered more normal; the 2006 line on this chart is starting to move closer to the other lines. Presenting the very same data in a slightly different manner yields the chart below.
Source: US Energy Information Administration
Basically, this chart compares current gas inventories to the five-year average. Positive numbers indicate how far above average inventories are; levels less than zero would, of course, suggest inventories of gas that are lower than average.
Peak excess inventories of natural gas totaled more than 600 billion cubic feet (bcf) in late spring and early summer. Although inventories are still above average, they haven’t been this close to average at any other time this year. At the very beginning of 2006, inventories of gas stood at around 200 bcf above normal; now inventories stand at just 185 bcf. That’s equivalent to just three days of US supply.
My point in all of this is to put gas inventory data in perspective. I hear this excess gas supply argument all over the media nowadays; the simple fact is that it’s not as bad as some are making it out to be. And the gas inventory picture has improved markedly since last summer.
A warm winter would leave the US with excess supplies of gas once again in 2007. One of the reasons gas prices dipped so precipitously in September was that the National Oceanographic and Atmospheric Association (NOAA) began to forecast a warmer-than-normal winter again this year. But, as I explained in the October 18 issue of TES, NOAA also was careful to state that this winter would be much cooler than last year.
Moreover, the “warm winter” thesis has already become conventional wisdom in the gas market. If NOAA gets it wrong and we get just an “average” winter heating season, I see big upside for gas.
Back To In This Issue
Drilling Activity
For much of the year, strong North American drilling activity presented a paradox. After all, with supplies of gas higher than average and prices falling for much of the year, it’s only logical to suspect that there would be a meaningful slowdown or at least a moderation in drilling activity.
This is the main reason I’ve been recommending avoiding the US-leveraged gas services stocks and land drillers for most of this year. But check out this chart of the current rig count.
Source: Bloomberg, Baker Hughes
This is the US land rig count—the total number of rigs actively drilling for oil and gas on land in the US. As you can see, the rig count has dipped slightly from its high in September. But that dip is almost imperceptible.
It’s not unusual to see the rig count pause like this before moving higher again. Bottom line: There doesn’t look to be much, if any, slowdown in US land drilling activity. But check out the Canadian rig count in the chart below.
Source: Bloomberg
There’s an obvious seasonality in the Canadian rig count; the rig count hits a low in the spring, then spikes higher through the summer, fall and winter.
Last year, the rig count in Canada spiked particularly high in the winter months. This was likely a response to the spike in natural gas prices in the wake of the vicious US hurricane season. The rig count then dropped off in March and April–fairly typical seasonal action.
What’s interesting is what’s happened since April. Specifically, the rig count never rose to levels as high as it has in past years. And rather than seeing continuing strength in Canadian rig counts as we head into winter, the active rig count appears to be continuing to slide lower.
My take is that these data are consistent with what we’ve heard from several services firms in recent months. The North American oil services market remains very strong with the exception of a few minor pockets of weakness. Those weak spots include coal-bed methane (CBM) and Canadian shallow gas.
CBM wells have an unusual production profile in that there’s initially a large rush of gas from these wells, followed by a particularly sharp production drop-off. As I outlined in the November 1 issue of TES, Earnings Bonanza, Schlumberger felt that some companies were holding off on producing CBM wells to try to “time” that initial rush of gas and take advantage of more favorable prices.
Another weak spot that Schlumberger highlighted was Canadian shallow gas. Canadian shallow gas has a relatively high cost of production; when natural gas prices are under $7 or so, shallow gas is marginally profitable to produce at best.
And with labor, raw materials and services costs more expensive than ever, this has further cut into the profitability of exploiting shallow-gas reserves. The weaker-than-normal Canadian rig count suggests that there’s been a significant moderation in Canadian shallow-gas activity this year.
I would note two points about all these data. First, North American drilling activity remains very strong and there’s been, at best, only a minor moderation in drilling demand. That bodes well for most services and equipment firms–companies that sell the products and services needed for all this drilling activity.
Second, with drilling activity still strong overall, it’s interesting that US gas inventories are moderating. This shoots holes in the thesis of those who were projecting that all this drilling would result in rapid production growth, ramping oversupply and collapsing gas prices.
This certainly doesn’t appear to be the case. It’s also worth pointing out that internationally, there’s been no slowdown in oil and gas exploration and drilling activity at all.
To play the still-strong global drilling and exploration markets, the best bets are oil and gas services companies. My favorites in the oil services and equipment business right now are, in no particular order, Schlumberger, Tenaris and Petroleum Geo-Services.
I’ve highlighted both Schlumberger and Petroleum Geo in recent issues of TES, including the November 1 issue. See that issue for my detailed rationale for owning these stocks.
Tenaris makes what are known as oil country tubular goods (OCTG). The company sells specialized pipes to oil and gas production companies. Once a well is drilled and completed, these pipes are the conduit through which hydrocarbons flow to the surface. Because of the high geologic pressures and temperatures that are commonplace in the oil and gas business, OCTG’s are manufactured to certain specifications set by the American Petroleum Institute.
Tenaris is the largest global manufacturer of tubular goods. The company has been highly acquisitive over the years, buying up local manufacturers all over the world.
By acquiring local manufacturers, Tenaris ensures that it’s located close to its key customers. Because pipe is heavy and bulky to transport, proximity to its customer base is key, allowing shorter lead times and faster service.
The company’s most-recent major acquisition was US-based Maverick Tube, a deal just completed in October. Although the US certainly isn’t the world’s largest producer of oil and gas, it is an extraordinarily intensive drilling market.
To produce more hydrocarbons out of America’s mature reservoirs requires continually drilling more wells. That’s why the US has, by far, the largest active rig count of any country on Earth. Drilling new wells requires laying new pipe. Maverick gives Tenaris solid access to the US market.
And not all OCTG are just commodity goods. Tenaris specializes in advanced seamless pipes. These OCTG pipes don’t have the welded seam that older pipes typically had.
This makes such pipes stronger and capable of withstanding higher heat and pressure. Drilling unconventional oil and gas wells and deepwater wells requires the use of these more-advanced pipes.
As outlined before in TES, deepwater and unconventional reserves are becoming the focus of a great deal of exploration and drilling activity because traditionally easy-to-produce onshore reserves are rapidly maturing. This trend bodes well for Tenaris; the stock remains a buy in the Wildcatters Portfolio.
Despite the relatively shallow decline in North American drilling activity, I continue to recommend avoiding stocks overly leveraged to the American market. This is particularly the case with companies overleveraged to commodity-type businesses.
For example, Patterson-UTI is a land-based contract driller; the company leases out land rigs to producers for a fee known as a day-rate. Patterson’s business is almost entirely US-based, and the company mainly owns relatively low-tech rigs. These rigs aren’t appropriate for drilling particularly deep wells.
Attracted to the high day-rates available in the US market, a flood of new commodity-type land rigs hit the US market in recent years. Continued strong activity has held day-rates aloft; even a minor slowdown in drilling activity could rapidly sour the business.
The same picture is true of companies leveraged to the pressure-pumping business. Recall that oil and gas exist underground in the pores, cracks and crevices of rocks, not in giant underground pools or caves. In some reservoirs, those pores aren’t well connected, making it difficult to produce the oil or gas; these reservoirs are poorly permeable.
To solve that problem, producers pump a gel-like liquid into the ground to crack the reservoir rock through a process called fracturing, creating channels through which the oil can flow to the well bore. Inside this gel-like liquid are small particles known as proppant. Proppant gets pushed into the cracks and crevices produced by the fracturing liquid; once the pressure is removed, these particles literally prop open the channels. This technique improves the permeability of reservoirs.
I suspect demand for pressure pumping will remain reasonably strong, given the importance of unconventional gas reservoirs that typically require pressure pumping; the problem is supply.
A record amount of pressure-pumping capacity has been built in the North American market. All that extra capacity will eventually start to weigh on pricing power. This is particularly true if drilling activity does moderate even slightly.
Earlier this year, I recommended a profitable short in BJ Services. Although it’s not a good time to short this stock again, I’d avoid BJ for now.
Another example of a vulnerable pressure-pumping focused services firm is Canada’s Calfrac. As the chart below illustrates, this stock has been particularly weak as of late.
Source: Bloomberg
As noted above, the weakness in Canadian drilling activity has been far more pronounced than in the US. Given Calfrac’s exposure to that market and to shallow-gas drilling, I suspect that’s why the stock is continuing to see so much weakness now. I recommend avoiding Calfrac right now.
Back To In This Issue
Crude Oil
I sent out a flash alert late last week discussing the implications of weakening very large crude carrier (VLCC) tanker rates in what’s normally a seasonally strong time of the year.
I suspect that Middle Eastern oil shipments are falling as a direct result of the Organization of Petroleum Exporting Countries (OPEC) output cuts announced during the past few months. Recall that when OPEC announced its production cuts, the cuts were widely derided as meaningless. The OPEC member states were all expected to “cheat” and produce more than allowed.
The weak fourth quarter VLCC tanker market suggests that’s absolutely not the case. We now have direct evidence that oil shipments from the Middle East are down. This is bullish for oil because it suggests lower import supplies.
But it’s not just tanker rates that should lead us to the conclusion that production cuts are having an effect on supply. Check out the latest oil import statistics from the American Petroleum Institute (API) pictured in the chart below.
Source: Bloomberg, API
The API import data is highly volatile from week to week; however, there’s an obvious spike to the downside in crude oil imports lately. Some of this could be random noise, but I suspect it’s also a result of lower shipments from the Middle East.
At any rate, despite all the talk of OPEC cheating on production cuts or the concept that OPEC is just trying to talk the oil market higher, there are concrete signs of falling crude oil trade activity. Bottom line: Falling crude oil supplies will support crude oil prices.
Back To In This Issue
Exploration And Production
Services and equipment stocks are one way to play the improvement in fundamental conditions for oil and natural gas. Another group that will benefit handsomely is the E&P industry. Just as with services, selectivity is paramount.
The E&P industry is among the simplest to understand in the oil and gas business: These companies look for, develop, produce and sell hydrocarbons. The type of reserves exploited by E&P firms differs widely between companies. Some of the largest independent E&Ps are targeting complex deepwater reserves, massive international projects and unconventional resources like the oil sands.
These larger E&Ps have come to resemble the large, integrated oil companies like ExxonMobil (NYSE: XOM) and Chevron (NYSE: CVX). And, of course, there are literally hundreds of smaller E&P’s operating worldwide, some targeting production from a single field or region.
Earnings for services and equipment firms are not directly tied to the price of natural gas and crude oil. That’s because services firms don’t product or sell any oil or gas. Instead, these firms are levered to oilfield activity–the more E&P activity going on globally, the greater the opportunity for the services companies.
In recent years, as oil producers have stepped up their exploration E&P activities, the services firms have benefited royally. So, too, have the equipment firms, selling valves, drill bits and pipe required for any drilling project.
For the services firms, the only link between profitability and hydrocarbon prices is indirect; higher commodity prices tend to encourage more E&P activity. But this link is tenuous.
For example, this year natural gas prices in the US declined sharply with only a minor impact on activity levels. When oil prices declined from $80 to under $60, there was no discernable change in drilling activity, demand for services or capital spending plans, particularly in international markets.
And because international oil and gas development projects tend to be large-scale, multi-year deals, exploration and development activity internationally is less closely tied to commodity prices than the small-scale projects that are so important in North America. Therefore, whether a services firm concentrates globally or locally has a major bearing on its leverage to commodity prices.
In contrast, the E&P business is intimately tied to the prices of oil and natural gas. This should be self-evident: if oil prices rise, then companies can sell their product for more money, hence earning higher profits.
Of course, effectively hedging future production in the futures markets means that E&P firms can lock in favorable prices. Hedging activity can protect E&Ps from temporary lulls in pricing. But at some point, no matter how well a company has hedged itself, a decline in hydrocarbon prices would have an impact on E&P profitability.
Although this distinction may seem obvious, many assume that all companies in the oil and gas business are simply levered to oil and gas prices. That’s just not the case.
And even E&P firms aren’t totally dependant on rising oil prices to keep their profits rolling; there are other factors at play that need careful consideration. Among the most important: production growth.
In the most-extreme case, an E&P firm with no production growth is totally dependent on the commodity markets for profits. Therefore, a 20 percent rise in oil prices would lead to a 20 percent rise in profits, assuming costs are stagnant.
But companies that grow their production over time have an advantage: Rising production can help offset the effects of falling commodity prices. By producing and selling more oil, a company can increase its earnings without depending totally on rising oil prices.
When hydrocarbon prices are rising, E&P firms with solid production growth benefit from a powerful dual trend: They’re able to bring more product to market in a favorable pricing environment. You can’t evaluate the E&P business by simply making a call on the future direction of oil and natural gas prices; just as with any other sub-industry in the energy business, E&P companies must be evaluated on a case-by-case basis.
For a more dramatic example of the importance of production growth and selectivity, check out the chart below.
Source: Bloomberg, The Energy Strategist
To make this chart, I examined the S&P Supercomposite E&P index–an index containing more than 20 US-based E&P companies of all sizes. I first threw out any that have been in operation for less than five years and sorted the remainder by their annualized production growth over the past five years.
After ranking the stocks, I selected the four firms with the best production growth over the past five years and the four with the worst production growth history. I created equal-weighted indexes out of these two groups of stocks, comparing the performance of my “Best” and “Worst” indexes with that of the S&P Supercomposite Index since Dec. 1, 2000.
These indexes don’t include dividends; this is of minor importance because most E&Ps in the index pay few, if any, dividends.
Note that my index of the “worst” E&Ps returned about 130 percent over the period in question. Although that may not seem too bad, it isn’t great when compared to the 205 percent gain in the Supercomposite index over the same time frame. Even more impressive, my “best” index jumped 791 percent; that’s a full six times the return from the “worst” index.
For comparison, the price of oil is up by roughly 140 percent since December 2000. Natural gas prices are actually down over the same time frame, but that’s an unfair comparison; December 2000 marked the height of major price spike for gas because of unusually cool weather nationwide and a series power crisis in California. If we look at average gas prices for 2000, the price of gas is up more than 50 percent since that year.
My point in highlighting all this is that E&P firms with the ability to grow production have been historically able to outperform slower-growing E&P companies and the prices of oil and natural gas. Such firms aren’t completely beholden to the price of oil and gas. Don’t assume that buying or selling E&P stocks involves simply making a broader call on the fortunes of oil and gas prices.
It’s also important to determine how E&P firms are generating their production growth. In the past, E&P firms often grew production via acquisitions; by purchasing smaller firms with attractive reserves, E&Ps can generate production growth without taking on the expense and risk of new drilling and exploration activity. That strategy works well when it’s relatively inexpensive to make acquisitions, such as when commodity prices are weak and smaller E&Ps are struggling to stay profitable.
Nowadays, however, acquisitions are hardly cheap. With oil and natural gas prices sitting at attractive levels and drilling activity strong, companies with attractive reserves and growth prospects are extraordinarily valuable. The cost of acquiring such firms has risen dramatically over the past five years.
Moreover, there’s already been a great deal of consolidation in the US and Canada during the past two decades. That means there are simply fewer “potential” targets for consolidation.
Because of the expense involved with undertaking a major acquisition, organic growth is of paramount importance. Companies with the ability to grow production simply by drilling more extensively on existing properties or exploring new formations in and around existing fields are in the catbird’s seat. Such firms have a chance to growth their production in an environment of high commodity prices. It’s these E&P firms that have the best shot at outperforming.
Meanwhile, E&Ps with stagnant organic growth are just commodity proxies; they’re likely to be particularly vulnerable to any swings in crude oil and natural gas prices. For such firms, the only prospect for growth is a rise in the price of the commodities they sell.
Another important consideration is, of course, a company’s cost structure. As I highlighted at great length above, Canadian shallow-gas drilling activity has fallen off severely this year; the reason activity has declined so much is that this is an expensive-to-produce resource. With gas prices falling sharply earlier this fall, some projects were simply no longer economical.
In addition, the cost of exploring for and developing reserves is also rising. One of the reasons that I’ve been so bullish on the services firms is that they currently have excellent pricing power; the cost of seismic services, pressure pumping, hiring rigs and just about any other service you can imagine is rising rapidly. Although this is excellent news for the drilling and services companies, it all spells rising costs for the E&Ps.
Another major cost center is labor. During the long depression in the oil and gas sector from the early 1980s to the late ’90s, it was tough for the industry to attract new talent. Many US universities stopped even offering courses in oil and gas engineering and geology.
The result: There’s a marked shortage of well-trained, experienced workers in the field. The few experts out there are in high demand and have seen their salaries shoot through the roof in the past few years.
To evaluate an E&P’s cost structure, I look at three different cost metrics. The first is what’s known as a lifting cost–the operating costs of producing oil or natural gas from a well. It’s calculated by dividing total production costs by oil and gas production for the year and is normally quoted in terms of dollars per barrel of oil equivalent production ($/BOE).
Some resources, such as Canadian shallow gas, carry higher production costs and are, therefore, more vulnerable to swings in hydrocarbon prices. This will show up in the form of higher lifting costs.
Another cost metric to watch is acquisition costs. This can be calculated by dividing total property acquisition costs (including buying drilling rights and buying other E&Ps) by the total purchases of reserves for the year.
This cost metric offers a good idea how expensive it is for particular a E&P to grow by purchasing reserves. Typically, this metric is also quoted in terms of dollars per BOE.
And finally, there’s the finding and development cost. This is basically the cost of adding reserves “through the drill bit”–actually going out and looking for new reserves of oil and gas.
In the table below, I list 33 of the US and Canadian E&P companies I follow. I’ve also included five-year annualized production growth and cost statistics for each E&P.
| Company |
Symbol
|
5-Yr. Prod. Grth. (BOE)
|
Lifting Costs ($/BOE) | Acquisition Costs | Find./Dev. Costs | Gas Prod. (BCF/Yr.) | Oil Prod. (MMBBL/Yr) |
| Devon Energy | DVN | 14.72 | 7.45 | 14.73 | 9.31 | 824.90 | 63.98 |
| Apache Corp | APA | 11.80 | 9.48 | 4.48 | 9.32 | 461.29 | 85.45 |
| Encana Corp | ECA CN | N/A | 7.39 | 12.01 | 5.69 | 1177.86 | 47.60 |
| Anadarko Petroleum | APC | 7.15 | 7.51 | 9.00 | 11.43 | 516.11 | 59.13 |
| XTO Energy | XTO | 24.31 | 5.02 | 10.19 | 7.51 | 377.10 | 14.25 |
| EOG Resources | EOG | 5.40 | 7.15 | 8.78 | 10.39 | 443.84 | 10.44 |
| Chesapeake Energy | CHK | 28.42 | 6.72 | 10.45 | 20.69 | 422.38 | 7.70 |
| Noble Energy | NBL | 13.89 | 5.61 | 9.74 | 32.09 | 185.49 | 21.97 |
| Southwestern Energy | SWN | 11.32 | 4.08 | 16.07 | 10.22 | 56.79 | 0.69 |
| Newfield Exploration | NFX | 11.52 | 6.68 | 8.34 | 15.22 | 190.90 | 8.43 |
| Pioneer Natural Resources | PXD | 8.09 | 7.01 | 2.14 | N/A | 244.74 | 16.09 |
| Denbury Resources | DNR | 6.84 | 2.54 | 14.00 | 10.69 | 21.42 | 7.30 |
| Cimarex Energy | XEC | 19.93 | 4.83 | 10.30 | 22.75 | 100.27 | 4.82 |
| Pogo Producing | PPP | 5.28 | 2.28 | N/A | 0.00 | 91.32 | 9.39 |
| Cabot Oil & Gas | COG | 4.77 | 7.36 | 21.85 | 10.37 | 73.88 | 1.75 |
| Quicksilver Resources | KWK | 24.88 | 5.04 | 50.50 | 8.45 | 93.51 | 1.09 |
| St Mary Land & Exploration | SM | 10.56 | 9.87 | 10.24 | 11.11 | 51.83 | 5.84 |
| Forest Oil | FST | -2.07 | 9.57 | 14.81 | 17.39 | 101.83 | 10.40 |
| Swift Energy | SFY | 7.07 | 9.01 | 6.52 | N/A | 23.62 | 5.16 |
| Penn Virginia | PVA | 18.24 | 6.79 | N/A | 12.90 | 25.55 | 0.30 |
| Stone Energy | SGY | -3.44 | N/A | 60.29 | N/A | 54.13 | 4.82 |
| Petroleum Development | PETD | 16.39 | 47.52 | N/A | 6.21 | 11.02 | 0.44 |
| Questar | STR | 8.58 | 6.30 | 30.01 | 20.86 | 110.01 | 2.37 |
| Canadian Natural Resources | CNQ CN | 16.06 | 9.66 | N/A | 15.06 | 525.24 | 114.25 |
| Talisman Energy | TLM CN | 2.99 | 13.62 | 22.22 | 32.37 | 380.77 | 77.84 |
| Nexen | NXY CN | 0.19 | 8.09 | 10.00 | 61.27 | 81.39 | 49.57 |
| Western Oil Sands | WTO CN | N/A | 48.75 | N/A | 19.80 | N/A | 11.68 |
| Compton Petroleum | CMT CN | 7.55 | 7.22 | 17.31 | 14.55 | 47.81 | 2.79 |
| Oilexco | OIL CN | 16.33 | N/A | 0.00 | 0.01 | N/A | 0.10 |
| Highpine Oil & Gas | HPX CN | N/A | 8.29 | 39.51 | 86.18 | 5.05 | 1.45 |
| Centurion Energy | CUX CN | 96.82 | 2.01 | N/A | 12.20 | 41.00 | 1.51 |
| Paramount Resources | POU CN | -8.23 | N/A | 121.38 | 88.06 | 44.75 | 1.13 |
| Petrobank Energy & Resources | PBG CN | -2.97 | 7.76 | N/A | 0.00 | 4.31 | 0.54 |
| Real Resources | RER CN | 28.77 | 8.01 | N/A | 46.63 | 11.48 | 1.66 |
| Nuvista Energy | NVA CN | N/A | 6.00 | 19.96 | 40.76 | 14.77 | 0.83 |
Source: Bloomberg, The Energy Strategist
I already recommend EOG Resources in the Wildcatters Portfolio. On a trailing five-year basis, EOG doesn’t have the fastest production growth of the E&Ps in my table.
However, that’s been changing, and the company is now targeting annualized production growth of about 10 percent. Close to 85 percent of the company’s annual production is natural gas.
The key to EOG’s future growth is its position in one of the US’s most-prolific gas plays, the Barnett Shale in Texas. With leases and drilling rights covering more than half a million acres, EOG is among the largest producers in the region.
The Barnett Shale is an unconventional gas reserve; it can’t be produced economically using simple traditional drilling methods. Specifically, the Barnett Shale lacks permeability so gas won’t naturally flow into wells.
To improve permeability, producers perform fracturing. Reservoirs of gas like the Barnett Shale that lack permeability and must be produced in this manner are known as tight gas plays.
The beauty of the Barnett Shale is that once wells are fractured, they’re extremely prolific. Even better, wells drilled in the region are long-lived. Specifically, shale wells tend to have very steep initial production declines; immediately after the well is drilled, it produces at an extremely high rate but production starts falling off soon thereafter.
However, after the initial production decline, shale wells tend to produce at a near-constant rate for years. That steady, predictable production rate is highly attractive for producers.
EOG’s strong position in the Barnett Shale means it’s likely to be able to meet its production growth targets without making large acquisitions. The company estimates its total reserves in the region at between 4.6 and 6.7 trillion cubic feet of gas.
EOG’s management has stated it intends to drill a total of nearly 2,500 wells in 2007, the majority in the Barnett Shale area. In total, the company has identified about 15,000 potential drilling locations.
EOG has plenty of growth potential simply by drilling on sites it’s identified on properties it already owns. As noted above, organic growth is desirable in this market because acquisitions have become extraordinarily expensive; companies that rely too heavily on acquisitions for growth will find their costs rise dramatically in the next few years.
For most of its history, EOG has focused on tight gas reserves. Therefore, EOG has a great deal of experience and know-how when it comes to identifying and producing such reserves. The Barnett Shale certainly isn’t the only major tight gas deposit in the US; EOG has built up considerable acreage in promising shale play regions all over the US and Canada.
EOG is careful not to reveal many of the locations where it’s buying up acreage because the company doesn’t wish to tip its hand to the competition. In many cases, EOG has been able to move into a promising new region and buy up property on the cheap before other competitors have a chance to move in and drive up prices. EOG will see considerable production growth from some of these promising new plays in the future.
Finally, it’s worth noting that EOG has been taking steps in recent quarters to cut its production costs on the Barnett Shale. The company has, for example, started using rigs that are specially customized for drilling tight gas deposits. By using these rigs, EOG has significantly cut down the amount of time it needs to drill a well.
In addition, EOG has experimented with optimizing how it performs fracturing work. This, too, has boosted efficiency and the speed with which EOG can drill new wells.
With plenty of room for organic production growth and some of the lowest overall cost metrics in the E&P business, EOG rates a buy.
Another US-based E&P that holds promise is XTO Energy. The company has grown production rapidly in the past five years; in fact, it has one of the fastest production growth rates of any US E&P. Like EOG, XTO primarily focuses on natural gas, although it’s boosted its oil output significantly in recent years and has actively purchased oil-producing properties.
XTO historically has grown through a combination of organic growth and acquisitions. On the organic growth front, XTO owns reserves in the Barnett Shale and in the Rockies. Like the Barnett Shale, the Rockies are a hot, nonconventional tight gas play. The company has identified several thousand potential drill sites; XTO has plenty of potential to grow production from its existing properties.
Unlike EOG, XTO does hedge some of its gas and oil production. In particular, the company has hedged close to 40 percent of its 2007 gas production at prices north of $10 per million British Thermal Units, a level significantly above current futures strip prices. These attractive hedges are one reason the stock has outperformed EOG this year.
XTO also has an attractive acquisition model. Basically, the company buys mature oil and gas properties with well-established reserves and production. Because these properties are already developed, XTO doesn’t take on any exploration risk. XTO then invests significant capital to exploit these reserves more effectively; the company is essentially squeezing more oil and gas out of these mature properties.
Although acquiring proven reserves in this manner has become more expensive in recent years, XTO has a history of making the strategy work and the company’s overall costs haven’t risen a great deal in the past few quarters. Management is targeting overall production growth in the low to mid teens; that’s considerably higher than average for US-based E&Ps.
I’m adding XTO to the Wildcatters Portfolio.
As it’s not a US or Canadian E&P company, I didn’t list Wildcatter BG Group (NYSE: BRG) in my table. However, the stock remains one of my favorite international E&Ps.
I like BG Group for a number of reasons. First and foremost, the company has some of the world’s most-attractive E&P assets; production is about 70 percent weighted in favor of natural gas, although the company’s oil assets are also attractive.
BG gets a little less than half its production from the UK’s North Sea gas fields. That gas is sold directly into Britain at attractive prices. UK gas prices are attractive because demand is high (due to new power plant construction), but supplies are diminishing as domestic gas fields are no longer sufficient to meet Britain’s growing needs. This is one highly profitable market for BG.
Outside Europe, BG is one of the most-interesting plays on liquefied natural gas (LNG). The company has gas fields in Egypt, Kazakhstan, Bolivia and Brazil. These assets are highly attractive because of their low production costs and large projected growth in production.
Because these are fairly immature fields, gas production can ramp up quickly. In fact, BG Group has some of the fastest gas-production growth of any major global E&P company. In 2001, the company produced 99 million BOE; last year, production was north of 500 million BOE.
Many of the company’s fields are so-called stranded gas fields, located miles away from existing pipeline infrastructure. But by liquefying the gas, BG can produce these fields and then ship the gas in the form of LNG to distant markets for sale at current sky-high prices.
BG is a key player in US LNG, a market that’s set to grow rapidly in coming years. The company has a LNG re-gasification terminal near Lake Charles, La., that can handle a daily capacity of 1.8 bcf of gas per day.
On the cost front, BG’s international reserves are extraordinarily cheap to produce. Unlike most US fields, BG’s international reserves are relatively immature; they produce at very high rates. The company’s lifting costs are around $3.60 per BOE, and finding and development costs around $9. BG Group remains a buy in Wildcatters.
Back To In This Issue
Going Platinum
My final recommendation this week will likely seem odd to TES subscribers: I’m adding a platinum mining company to the Gushers Portfolio. Like the railroads and airlines I’ve recommended, platinum may seem at first blush to have absolutely nothing to do with energy; in fact, platinum is a crucial commodity that’s intimately tied to the future of clean diesel fuel.
As I’ve highlighted before in this journal, diesel fuel is a fast-growing fuel worldwide. Diesel-powered cars get as much as 40 percent more miles per gallon compared to similar-sized gasoline engines. Moreover, with the advent of turbo direct injection, diesel cars actually offer performance that’s comparable to or better than equivalent gasoline engines.
Because of this fuel efficiency, diesel is picking up market share all over the world. In 2006, diesel cars accounted for more than half of the European car market; that’s the first time diesel has been more important than gasoline in Europe.
And diesel is also becoming a key fuel in fast-growing Asian markets; in 2004 alone, diesel demand in China soared more than 350,000 barrels per day. Longer term, China’s diesel demand should grow between 100,000 and 200,000 barrels per day every year. Overall, growing demand in the European Union, US and Asia represents as much as 650,000 barrels per day in annualized growth in demand for diesel fuel.
Then, of course, there’s the US. Diesel has always had a less-than-stellar reputation in the American market. That’s partly because early diesel cars sold in the US market weren’t of the best quality.
Early models were plagued by poor performance, particularly in cold weather conditions. That turned off an entire generation of Americans to diesel fuel. But diesel is predicted to make somewhat of a comeback; the US Dept of Energy believes that diesel could account for 8 percent of the US car market in 2030, up from around 2 percent today.
And diesel has always been the fuel of choice for trucks and trains in all markets. This is likely to remain the case.
But there’s a problem with the increased use of diesel fuel: Diesel produces a good deal of pollution. Pollutants emitted from diesel engines include sulphur dioxide, nitrous oxides and particulate matter (basically soot).
Particulate matter is particularly troubling for diesel cars. In China, burning diesel fuel is one of the main culprits for the major Chinese urban pollution problem. The Chinese government has expressed interest in controlling the problem because it’s actually impacting growth potential.
Most governments are tightening environmental regulations for diesel fuel. This includes producing fuel with ultra-low sulphur content and imposing limits and regulations covering emissions from diesel-powered vehicles. This isn’t just a developed market story; China and India are also cracking down on diesel pollution.
One of the offshoots of this environmental regulation is that diesel-powered cars and trucks will need to be fitted with special filters that cut down on emissions of sulphur and nitrous oxides and particulate matter. The key component of diesel filters: platinum.
If you’re like most people, when you think of platinum, jewelry is probably the first product that springs to mind. But platinum jewelry accounts for only about a quarter of global platinum consumption.
The autocatalyst market is far more important: More than half the platinum consumed globally goes into automobile and truck filters. It’s far and away the most-important and fastest-growing use for the metal.
Because Europe is now the world’s largest diesel market, demand for platinum has been soaring there. Check out the chart below for a closer look.
Source: Johnson Matthey Platinum 2006 Review
Europe now accounts for 37 percent of global platinum demand. Demand in Europe for platinum as an autocatalyst has grown from 500,000 ounces in 1997 to more than 2.25 million this year.
But Europe isn’t the whole story. In North America, demand for platinum as an autocatalyst grew 130,000 ounces this year to total nearly 1 million ounces and emerging markets sucked down 650,000 ounces up from around 250,000 a decade ago. Demand is projected to continue accelerating as new tighter environmental regulations are phased in.
Of course, as with any commodity, there are two sides to the platinum story: demand and supply. And when it comes to platinum supply, South Africa reigns supreme.
The country accounts for close to 80 percent of global platinum supplies. South Africa is also the only nation globally that’s been able to significantly boost production in recent years. In other words, it’s a crucial piece of the global diesel market.
Although the supply-and-demand balance in the platinum market is improving, the market still faces a deficit and is likely to remain in deficit again in 2007. In other words, demand for platinum exceeds available supply. Check out the chart of platinum demand and supply below.
Source: Johnson Matthey Platinum 2006 Review
With demand for platinum rising rapidly, mine production will have to rise even faster to keep up with the demand. Most of the additional supply will come from South Africa’s prolific mines. This tight supply-and-demand balance is behind platinum’s big rally during past few years. Check out the chart below for a look at platinum spot prices.
Source: Bloomberg
The world’s largest platinum producer is South Africa’s Anglo Platinum, sometimes called simply Amplats (Johannesburg: AMS, London: ANP; OTC: AGPPY). This company alone produces 40 percent of the world’s platinum–close to 2.5 million ounces annually from mines located mainly in South Africa. The company is 75 percent owned by Anglo American but is traded separately.
Amplats is certainly benefiting from the bull market in platinum as it’s one of the only companies in the world with the ability to actually grow supplies of platinum to meet rising demands. Subscribers looking for a big cap play on platinum should definitely consider buying Amplats.
However, I’m adding a far-riskier and more-leveraged play to the Gushers Portfolio this issue—Platinum Group Metals.
Platinum Group owns a platinum reserve located adjacent to Amplats Bushveld mining complex, one of the world’s most-prolific platinum mines. It’s still an exploration story; Platinum Group isn’t likely to start producing platinum any time soon. However, what gives me confidence is the fact that the company is part of a joint venture to produce its mine in the Bushveld area.
The other major partner in the mining operation is none other than Anglo Platinum itself. Given just how close Platinum Group’s mine is to Amplats’ own operation, one can only assume that Amplats is well aware of the geology and potential for this mine. The fact that they’ve invested in the project suggests that it holds promise.
Please keep in mind that Platinum Group Metals is a very small company, and this is a highly speculative and risky stock to own. I’d recommend keeping your position size relatively small in this stock.
The advantage of buying Platinum Group over Amplats is that it also has much higher upside potential; speculative mining plays can double or triple in the blink of an eye if they’re reserves pan out. Platinum Group Metals is added to the Gushers Portfolio.
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