Gas over Oil

The winning theme for the past two years was bullish on oil, bearish on natural gas. This year, however, that’s reversing.

Oil prices could continue to climb near term because of a weak US dollar. However, that rally isn’t grounded in the fundamentals of the oil market; there’s room for a pullback into the $80s if the dollar gets even a temporary reprieve.

I’m also growing concerned about the refiners. Crack spreads should see some seasonal upside before the end of spring, but the gasoline market looks well supplied.

In contrast, natural gas inventories are normalizing, and gas demand and prices in Europe and Asia are higher than in the US. It’s time to focus more attention on this long-ignored market.

In This Issue

Gas prices have vastly outperformed oil this year. Gas inventories continue to slip and may hit below five-year averages ahead of the summer cooling season. See Oil and Gas.

Canadian gas producers have suffered from a vicious one-two punch over the past few years, thanks to a decrease in price and a government-imposed trust tax announcement in 2006. But Canadian gas production is set to rise significantly in coming years. See Canadian Drilling Decline.

Part of the drop in gas prices was caused by a surge in liquefied natural gas imports. However, this factor doesn’t appear to be a repeat issue this coming year. See Liquefied Natural Gas Supplies.

Oil’s rise past $100 was hard for any investor to miss as global demand continues to increase and traders continue to use it as a hedge against weakness in the US dollar. But a faster-than-expected increase in US oil inventories may mean a short-term pullback in the commodity. See Back to Oil.

If the price of oil does in fact fall, refiners may be able to capitalize. The action in refining stocks is leveraged to the value of the crack spread between oil and gas prices, so if one or the other is increasingly affected, it may work in the refiners’ favor. See Refining Bears.

Long term, US refining capacity is expanding, and the market is likely to loosen over the next few years. I’m looking for a moderation in the refining environment. See Longer-Term Outlook.

I hold four refining plays in the TES Portfolio. Most appear to be doing quite well in this market, but there are a few items I’m watching going forward. See How to Play It.

I’m recommending or reiterating my recommendation in the following stocks:
  • Chevron Corp (NYSE: CVX)
  • EOG Resources (NYSE: EOG)
  • Hercules Offshore (NSDQ: HERO)
  • Nabors Industries (NYSE: NBR)
I’m recommending holding or standing aside in the following stocks:
  • Dresser-Rand (NYSE: DRC)
  • NuStar Energy (NYSE: NS)
  • Valero Energy (NYSE: VLO)

Oil and Gas

Crude oil’s relentless rise to new all-time highs continues to grab the headlines in the mainstream and financial media alike. Meanwhile, most continue to ignore the far larger story this year: the surge in natural gas prices. Check out the chart below.

Source: Bloomberg

This chart shows the relative performance of oil and natural gas prices since the beginning of 2008. I used the 12-month New York Mercantile Exchange (NYMEX) strip prices for both commodities. Long-term TES readers are familiar with the strip price; it’s simply the average of the next 12-months’ worth of futures prices.

The strip is useful because it smoothes out seasonal variations in commodity prices. It also most closely reflects the price a producer faces. Producers routinely use the futures market to lock in attractive prices for their production.

What’s clear is that natural gas prices have vastly outperformed oil so far this year. Natural gas is up more than 30 percent compared to just 13 percent for crude oil. The 12-month natural gas strip price is now solidly above $10 per million British thermal units (MMBtu); gas has finally broken above the $7 to $9 per MMBtu trading range that was in place for most of 2006 and 2007. This is a significant change, illustrated in the longer-term chart of the natural gas strip below.

Source: Bloomberg

As I’ve noted in TES this year, I see natural gas prices remaining broadly in the $8.50 to $10.50 per MMBtu region this year. The risks to that forecast are mainly to the upside: A hot summer could drive higher demand, and any supply disruptions caused by an active Atlantic hurricane season would also be bullish for gas.

The most obvious driver for gas prices has been the normalization of natural gas inventories that’s occurred over the past few months. The last time gas prices were above $10 per MMBtu was back in late 2005 and early 2006. Back then, the prime driver for gas was supply disruptions in the wake of the devastating 2005 Atlantic hurricane season.

But the winter of 2005-06 was among the warmest on record in the US, particularly in some of the areas of highest gas consumption. Warm weather meant lower demand for gas, and inventories looked bloated by the end of the 2005-06 winter heating season.

To make matters worse, producers continued to drill relatively aggressively in the first half of 2006. See the charts below.

Source: Bloomberg, Baker Hughes

Source: Bloomberg, Baker Hughes

As these charts illustrate, the US active rig count–the number of rigs actively drilling for oil and gas–remained strong in the first half of 2006 despite weakening gas prices. In fact, year-over-year growth in the rig count was hovering around 20 percent.

This can’t be explained by an increase in oil drilling activity because more than 80 percent of all rigs working in the US are targeting gas, not oil. And the rig count was also growing strongly in early 2005. This chart can’t be explained away by easy comparisons with the year-ago period either.

And the picture in Canada is much the same, with strong year-over-year growth in the rig count in early 2006. Growth was mainly a result of gas drilling activity.

This isn’t all that unusual. Many producers regarded the pullback in gas in early 2006 as temporary. And predictions of another deadly hurricane season were rife at that time; some saw a repeat of the 2004 and 2005 active seasons and the potential for a spike to as high as $20 per MMBtu.  

And don’t forget that many producers hedge their production, locking in prices for months in advance. Because many hedged their production in the sky-high pricing environment of late 2005, falling gas prices didn’t have an immediate impact on the bottom line.

Gas drilling projects in North America are short term in nature and can be delayed or canceled relatively easily. However, for the first few months of 2006, many producers likely decided to stick with their drilling plans drawn up during the more favorable environment of late 2005.

But no matter what the rationale for continued drilling activity, the result was continued production growth. And higher supply, coupled with weak demand, spelled soaring inventories and tumbling prices by mid-2006.

The 2006-07 winter heating season was more normal, and a late-winter cold snap in 2007 helped reduce gas inventories. However, last spring, imports of liquefied natural gas (LNG) soared.

This flood of gas pushed inventories right back up to record levels by the end of last summer. Gas prices showed some strength early in 2007 but collapsed to the low end of their trading range by summertime.

This year, however, strength in gas prices looks far more sustainable. Check out the chart below.

Source: Energy Information Administration

This chart includes four lines showing the maximum, minimum, average and current natural gas inventories in the US. Since the beginning of 2008, inventories have fallen from the top end of the average range to only slightly above five-year averages.

As you can clearly see, gas inventories should continue to fall generally for a few more weeks before hitting a seasonal low in early April; this low corresponds to the end of the winter heating season. There’s a good chance inventories will actually fall below that five-year average before the end of the heating season. Such a move would likely trigger another wave of gas buys.

Although it’s almost impossible to predict the weather with any degree of accuracy over the remainder of the season, the factors that have scuttled the gas rallies over the past two years aren’t present this year.

Back to In This Issue

Canadian Drilling Decline

First, as the charts of drilling activity above illustrate, producers aren’t exactly drilling aggressively in the US or Canada. The US rig count is roughly flat over the past year. And in Canada, the situation looks far direr: The Canadian rig count declined sharply last year and shows little sign of recovery. The slight uptick in recent weeks is more the result of easy comparisons with early 2007 than any real increase in activity levels.

Canadian gas producers have suffered from a vicious one-two punch over the past few years. First, and most important, the decline in gas prices started impacting the bottom line in mid-2006. Then, Canada made a series of tax changes at both the national and provincial levels.

As most subscribers are well aware, the Canadian government decided to tax Canadian royalty trusts starting after 2011. The government announced the decision on Halloween 2006. Taken as a whole, trusts are key gas producers in Canada. Many target more expensive-to-produce mature gas fields in Canada; production from these fields was already challenged in late 2006 by weakening gas prices.

I’m not saying the tax change ruined the investment potential of the Canadian trust sector; some good values remain, particularly with gas prices ticking higher now. However, the trust tax law introduced a level of uncertainty and didn’t exactly encourage an aggressive expansion in drilling activity.

Then, on the provincial level, Alberta recently decided to change its royalty structure. Clearly, this change is also having an impact. US-based exploration and production (E&P) company Apache Corp (NYSE: APA) noted this change in its recent conference call.

Canada is one market where Apache had planned a large increase in capital spending on new gas drilling projects. The company has decided not to cut its Canadian spending plans for 2008; however, the change in the Alberta royalty structure did change its intentions as to where to spend the cash. Apache’s CEO G. Steven Farris noted:

…the current structure of the Alberta royalty is both a [production] rate and price curve. And so at lower rates, you actually pay a lower rate than you would under the old regime and as you go higher, you pay a disproportionate higher price. Which is why we curtailed our deeper drilling activities, because they generally come on at higher rates. If you get a 5 [million cubic foot] per day well, for instance, the royalty today in Canada under the new regime is 50 percent, which seems exorbitant to us…

Source: Apache Corp Fourth Quarter 2007 Conference Call, hosted Feb. 7, 2008.

The point is that tax law changes, coupled with weak gas prices, have hit Canadian gas drilling activity hard over the past year and a half. At this time, the sharp falloff in drilling activity isn’t showing up in the form of rapidly falling exports of Canadian gas to the US market. However, there are certainly some early signs of trouble to come.

Roughly 98 percent of Canada’s gas production comes from a region known as the Western Canada Sedimentary Basin (WCSB). The WCSB spans several provinces, but Alberta is the most important. See the chart “Canada Natural Gas Reserves in Place” for a closer look.

Source: Canadian Association of Petroleum Producers

Clearly, understanding production trends from the WCSB and Alberta is key to projecting Canada’s gas supply. Canada’s National Energy Board (NEB) attempts to make short-term predictions of Canada’s gas supply each year; its most recent report, released last October, highlights some fascinating trends.

First and foremost, according to the NEB, half of all WCSB gas production at the end of 2006 came from wells that are less than 5 years old. See the chart below for a closer look.

Source: NEB Short-Term Canadian Natural Gas Deliverability 2007-09

In April 2007, wells drilled prior to 2002 accounted for 54 percent of total Canadian gas production, while wells drilled in 2006 and early 2007 accounted for nearly a third. This chart illustrates that relatively new wells are crucial to WCSB gas supplies.

The reason for that trend is rapid decline rates for Canadian wells. Again, according to the NEB, the average Canadian gas well sees production decline by 55 percent in the first year and a half alone. Following that initial decline, the rate slows to a still-hefty 30 percent for the following two years. And the NEB goes on to state that well decline rates have been increasing since the late 1990s.

For example, gas wells drilled in 2002 produced 2.93 billion cubic feet (bcf) per day in December 2002. By December 2003, production had declined 37 percent to just 1.873 bcf per day. And by April 2007, those 2002 vintage wells produced less than 0.8 bcf per day, a production decline of 75 percent in less than five years.

In order to offset declines in production from existing wells, producers must aggressively drill new wells. This is why Canada is so reliant on new wells for gas production.

This factor also introduces a high level of uncertainty into NEB production estimates. Canadian gas production is highly dependant on expectations for future drilling activity, and those plans can change quickly because of changes in commodity pricing.

What’s clear is that gas drilling activity has slowed markedly since mid-2006. As a result, NEB revised lower its forecasts for future gas production in its October 2007 report. The following chart shows NEB gas production estimates out to 2009.

Source: NEB

This chart uses actual historical Canadian production data going up to May 2007; after that, I’ve used NEB projections. The prior estimates from NEB, published in late 2006, had projected production to remain relatively constant out to 2009. But this new model projects a significant decline in production as the rapid, severe falloff in drilling activity finally catches up to producers. Simply put, there aren’t enough new wells to make up for rapid production declines from older wells.

At the same time, Canadian gas production is set to rise significantly in coming years mainly because of a rapid ramp-up in demand from the oil sands industry. According to NEB, Canada’s own demand for gas is projected to rise from 4.7 bcf per day at the end of last year to 5.23 bcf per day by the end of 2009. Coupled with declining production, this trend suggests a further tightening of North American gas supplies.

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Liquefied Natural Gas Supplies

The factor that routed gas prices last spring was a surge in imports of LNG. LNG is nothing more than gas that’s been supercooled into liquid form. LNG doesn’t have to be transported by pipeline; it can also be loaded onto tanker ships and shipped anywhere in the world.

But there’s little risk of a surge in LNG imports this year. LNG imports are mainly a function of relative regional gas prices. This is rather obvious: If you’re a producer with available LNG supplies, you’ll ship those cargoes to the market where you can get the most favorable prices.

Last spring, a mild winter in Europe reduced European Union (EU) gas demand to unusually low levels. Therefore, gas prices in Europe were actually lower than in the US. Check out the chart below.

Source: Bloomberg

This chart shows US gas prices divided by gas prices in the EU. I’ve used the 12-month strip prices for gas traded on NYMEX and in London to make this chart.

Gas prices in London are traded in terms of British pence (1 pence = £0.01) per therm (100,000 Btus), while NYMEX prices are quoted in dollars per million Btus. I made the appropriate currency and unit conversions before calculating the ratio.

To make a long story short, when the ratio is above 1, US gas prices are higher than gas prices in Europe. This would encourage LNG imports to the US. When the ratio is less than 1, that LNG would likely head to Europe, where prices are more attractive.

As you can see from the chart, US gas prices were as much as two times European prices last spring. This made it highly attractive to ship LNG cargoes to the US instead.

But this year, thanks to a combination of the weak US dollar and strong demand and pricing in the EU, European prices are higher than in the US. The simple ratio is less than 1. That means that LNG cargoes aren’t entering the US market this year as they did a year ago.

The chart below shows data on LNG imports into the US.

Source: EIA

The EIA released data on gas imports and exports with a lag; the most recent data are from December 2007. Nonetheless, the trend here is clear. After surging in early 2007, LNG imports have absolutely collapsed to levels unseen since early 2003.

As long as demand and pricing for gas remains stronger overseas than in the US, LNG will likely head elsewhere. Gas prices in the US would need to increase to roughly $12.50 to $13 per MMBtu for the nation to really start attracting marginal LNG supplies.

We’re already playing the natural gas turnaround profitably in the TES portfolios–in particular, the gas-focused producers I outlined in the Feb. 20 issue, Growing Unconventionally. The list includes Wildcatters EOG Resources, BG Group and XTO Energy, as well as Gushers Portfolio pick Quicksilver Resources.

I’m raising my buy target on EOG to reflect the company’s recent potentially huge gas find in Canada, as well as its exposure to the hot Bakken oil play in Montana and North Dakota. EOG Resources now rates a buy under 130.

Producers clearly benefit directly from higher natural gas prices: They can sell their production at more attractive prices. All the producers I recommend focus on fast-growing, high-quality unconventional reservoirs. These companies have the ability to grow production cheaply in an attractive pricing environment; the current environment is favorable for these companies.

In addition, since early 2006, exposure to North American gas drilling markets has been a major headwind for any contract drilling and services firms. But with gas prices firming up, I’m looking for some stabilization in drilling activity; the headwind is abating and will likely soon become an important tailwind.

My favorites in this regard include Nabors Industries and Hercules Offshore, both holdings in the Gushers Portfolio. I highlighted Hercules in the Feb. 6 issue, Earnings on Tap, and Nabors in the March 5 issue, The Final Frontier. Both Nabors Industries and Hercules Offshore remain buys.

Back to In This Issue

Back to Oil

Although the sharp move higher in natural gas has been largely ignored, few investors could have missed the fact that crude recently touched all-time highs of more than $110. Unlike the move in natural gas, the move in crude since the beginning of 2008 isn’t rooted in the fundamentals of supply and demand.

As I highlighted in the last issue of TES, I’d been looking for crude oil to pull back this year; I was wrong in that assessment. Nonetheless, my fundamental outlook remains unchanged.

Last year, I was consistently bullish on crude up until late November. I heard many pundits suggesting the run-up in crude in 2007 was based on rampant speculation. I totally disagree; crude rallied last year because of continued strong demand growth coupled with weak supply.

I outlined this bull case for oil on several occasions last year, so I won’t belabor the point. Suffice it to say that supply growth from non- Organization of the Petroleum Exporting Countries (OPEC) countries disappointed expectations last year after a series of project delays and higher-than-expected decline rates from existing fields.

A perfect example of the latter problem is Mexico. According to the Oil and Gas Journal, that nation’s giant Cantarell field saw oil production decline by 304,000 barrels per day in 2007. That decline was on top of a 234,000-barrel-per-day decline in 2006 and 101,000-barrels-per-day drop in 2006.

That was partly offset by some new field developments; however, those newer fields weren’t enough to offset the faster-than-projected, accelerating decline at Cantarell: Mexico’s total oil production declined by 174,000 barrels per day last year. That decline is expected to accelerate through at least 2010.

Meanwhile, OPEC countries remained disciplined in their production. And, of course, demand growth—particularly from the developing world—remained strong. The result: Oil inventories drew down globally toward the latter half of 2007 at a time of year when inventories typically rise.

The crude oil market tends to focus on US inventory numbers for short-term direction even though the developing world has been the real fundamental driver of oil market demand in recent years. The fall in US oil inventories into the fourth quarter is unusual and helped to accelerate the rally in oil prices.

For the next quarter or two, however, the fundamental picture for oil looks more troubled. It’s important to distinguish short-term outlook from long-term trends; the end-of-easy-oil thesis I outlined in the most recent issue of TES is still intact, and bringing new sources of oil online will be more difficult and expensive than it has been in the past.

Meanwhile, delays to non-OPEC projects and accelerated decline rates from aging fields are long-term, not short-term, problems. And the emerging demand picture I highlighted at length in the Jan. 23 issue, Strengthening Headwinds, also remains bullish.

However, none of these factors preclude a pullback to the $75 to $85 region for crude on a short-term basis. As I noted earlier, the crude oil market tends to get its short-term direction from US oil inventories and demand. For a closer look, check out the chart below.

Source: EIA

This chart shows US oil inventories compared to the five-year maximum, minimum and average. US oil inventories were below-average in the final months of 2007 and into the first few weeks of this year. Now oil inventories are in the upper half of the average range.

The EIA releases crude oil inventory data each Wednesday at 10:30 am. In seven out of the past 10 weeks, crude oil inventories have built up at a faster-than-projected pace. And although crude oil inventories are essentially in line with the five-year average, inventories of gasoline in the US look terribly bloated. Check out the chart below for a closer look.

Source: Bloomberg

This chart shows that gasoline inventories have soared this year, well above the upper end of the five-year range. Although gasoline prices have been dragged higher with crude, the US looks more than well supplied with gasoline ahead of the upcoming summer driving season.

I won’t belabor the point by showing a chart of distillate inventories. (This is a category of refined product that includes diesel, jet fuel and heating oil.) Distillate inventories are tighter than gasoline, and heating oil prices have broadly outperformed gasoline in recent weeks. However, inventories are still about average for this time of year.

To make a long story short, the US inventory picture doesn’t appear supportive of higher oil or refined products prices. And although demand from the emerging markets has remained resilient, the combination of high energy prices and a slowing economy is likely to moderate demand in the developed world to at least a minor extent. I see little fundamental reason for oil to be trading at current levels.

Instead, crude is currently being driven by one force alone: weakness in the US dollar. Check out the charts of crude oil below.

Source: Bloomberg

Source: Bloomberg

These charts show crude oil priced in euros and Japanese yen, respectively. Although crude has rallied in dollar terms this year, it’s actually flat in euro terms and has fallen on a yen basis.

Of course, this argument is a bit academic because crude oil is priced in dollars. However, my point is that crude is being used as a means for traders to hedge against further downside in the dollar. This accounts for oil’s tendency to rise sharply every time the Federal Reserve cuts rates or makes dovish comments.

The turn in the oil market this year will likely come when the US dollar bounces. The only catalyst I can imagine for such a turn would be a change in monetary policy for the European Central Bank and Bank of England. I expect both central banks to eventually join the Fed in cutting rates to combat economic softening; however, that change in policy could still be months down the road. Until that time, there’s more room for the dollar to weaken, and that selloff could accelerate if the Fed is perceived to be getting desperate to stem a financial crisis.

Currency bets are beyond the scope of this newsletter. The reason for bringing up these points is to say that I’m not recommending a short in oil or the US Oil Fund (AMEX: USO) at this time because there’s a valid case to be made that a quick selloff in the dollar could result in a spike to $130 per barrel or higher in the next few months.

Once again, I’m more excited about the natural gas market right now because the rally in gas is more than just a currency trade; it’s supported by the fundamentals.

Another point worth mentioning in this regard is that oil prices and energy stocks aren’t perfectly correlated. For example, although crude oil has made new highs this year, the S&P 500 Energy Index is off around 9 percent. This divergence suggests that traders understand crude oil’s move this year is mainly a function of the weakness in the dollar, not stronger fundamentals.

The good news about this is that, because energy stocks haven’t fully participated in oil’s upside, I don’t expect to see the group sell off aggressively if crude pulls back.

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Refining Bears

There’s one group about which I’m increasingly becoming concerned: refiners. Refiners are among the most misunderstood industries within the energy patch. All too often, I’ve heard pundits pitch the refiners as a play on rising crude oil and energy prices. This is totally incorrect; more often than not, refiners are actually hurt by rising crude oil prices.

I’ve highlighted the fundamentals of the group at great length before in TES. (The March 21, 2007, issue, Looking Refined, offers a detailed look at the fundamentals of the industry.) To summarize, refiners perform the crucial function of converting raw crude oil into usable refined products such as gasoline, diesel fuel and heating oil.

Some of the nation’s largest refiners are part of the integrated oil companies like Proven Reserves recommendation Chevron Corp. Integrated oils typically earn the lion’s share of their profits from the actual production of oil and natural gas and a smaller amount from refining. For example, Chevron’s business is roughly 75 percent E&P and 25 percent refining.

The integrated oils can use the oil they produce as feedstock for their refineries. Typically, the integrateds will use a combination of their own oil production and oil purchased from third parties to feed their refining business. For those wondering, the integrated oil firm with the most leverage to refining is Marathon Oil Corp; refining accounts for between 40 and 50 percent of Marathon’s business.

There are also a number of publicly traded companies that are pure plays on refining. Typically, these are termed independent refiners. Independent refiners must buy crude oil from third-party suppliers to feed their operations.

But no matter what sort of company owns the refinery, crude oil feedstock represents a cost for refiners. In other words, with crude above $100, refiners are paying more to buy feedstock for their operations.

What refiners do sell is refined products such as gasoline. Therefore, these companies actually profit from the spread between the cost of crude and the value of the refined products they sell.

If the price of gasoline rises faster than the price of crude, profit margins for refiners would tend to expand. And refiners can, of course, actually make money when crude oil prices are falling. For example, if crude prices are drifting lower but gasoline costs are rising or remaining steady, this will support refiners’ margins.

The basic measure of a refiner’s profitability is what’s known as a crack spread. The term comes from the fact that refiners are said to “crack” a barrel of crude to make refined products. The crack spread is generally calculated by comparing the cost of crude oil futures with the price of refined products futures–typically gasoline and heating oil futures.

One of the most common forms of the crack spread is known as the 3-2-1 crack spread. It’s calculated by adding the price of heating oil per barrel to twice the price of gasoline per barrel. Triple the price of a barrel of crude oil is then subtracted from that total. The best way to illustrate is with a simple example.

Crack Spread Example
Crude Oil (per barrel)
Gasoline (per gallon) 2.52
Heating Oil (per gallon) 3.08

Heating Oil x 42 $129.34
Gasoline x 84 21..68
Less Crude Oil x 3 318.36
3-2-1 Crack Spread (three barrels) 22.66

Crack Spread ($/Barrel) $7.55
Source: Bloomberg

The current crack spread is about $7.55 per barrel. Gasoline and heating oil futures prices are both traded on a per-gallon basis on NYMEX, while oil is traded on a per-barrel basis. There are 42 gallons in one barrel.

To arrive at the crack spread, I calculated the value of 84 gallons of gasoline (two barrels) and 42 gallons of heating oil (one barrel) and subtracted the cost of three barrels of crude oil. I then divided this result by three to yield a per-barrel cost.

The action in refining stocks—particularly the independent refiners—is leveraged to the value of the crack spread, not the price of crude oil or gasoline alone.

But consider this crack spread calculation in light of my analysis of the oil and gasoline markets above. As I noted, crude oil prices have been soaring mainly because of currency effects; inventories of crude in storage are about average for this time of year.

Meanwhile, gasoline inventories are extraordinarily bloated at this time. And gasoline isn’t as widely traded internationally as crude; most funds and traders are using crude, not gasoline, to hedge against the weakening dollar. The result: Crude oil futures have been rising at a faster pace than gasoline.

Based on my calculation of the crack spread above, it’s easy to see why such an environment is bearish for refiners. In order to see the crack spread improve, we need to see either crude oil prices decline or gasoline inventories tighten, sending gasoline prices higher relative to crude.  

Even more worrisome, check out the two charts of the crack spread below:

Source: Bloomberg

Source: Bloomberg

The first illustrates the basic chart of the crack spread over the past few years. The trend here is obvious: The crack spread has been declining in recent weeks and is at a generally low level because of the rapidly rising price of crude oil.

The second chart depicts the crack spread on a seasonal basis for each of the past five years. I normalized the crack spreads, scaling the values to an index level of 100. The trend to note here is that, in most years, the crack spread tends to expand from late January/early February through to the end of April or early May. The weakest part of the year for the crack spread is typically from June through September/October.

There are some exceptions to this rule. The prominent spike you see in this chart in the late summer months represents 2005. In that year, hurricanes Katrina and Rita caused widespread disruptions to refining operations along the Gulf Coast. The sudden drop in refining capacity sent crack spreads sky-high.

The late winter/early spring months are positive for crack spreads because this when refiners tend to gear up their operations ahead of the summer driving season. Last spring was a particularly good year for crack spreads because a series of refineries experienced outages or fires, and gasoline inventories fell to dangerously low levels. The crack spread spiked more than $30 per barrel in May 2007.

This year, however, crack spreads aren’t following the normal seasonal pattern. Sky-high gasoline inventories are putting pressure on prices (at least relative to crude). Meanwhile, the dollar effect is artificially boosting crude oil prices. The result: Refiners are getting squeezed right now during a time of year when you’d normally expect to see crack spreads rising.

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Longer-Term Outlook

One of the first issues of TES highlighted refiners as a favored group. My long-term outlook was simple: Refining capacity just wasn’t keeping up with growth in demand for refined products. That situation meant refining margins would generally trend higher, short-term seasonal gyrations aside.

I see at least a short-term pause in this dynamic. Specifically, no new refineries have been built in the US since 1976, and I suspect that won’t change. Regulations and permissions for building a new refinery in the US would be onerous. At the same time, demand for refined products has been showing slow-but-steady growth for years.

That said, just because no new refineries have been built doesn’t mean that US refining capacity is stagnant. Check out the chart “US Operable Refining Capacity” for a closer look.

Source: EIA

This chart shows US operable refining capacity going back to 1985. Starting in the late ’90s, refining capacity began to climb, even though no new refineries were constructed, because operators added capacity to their existing facilities.

In addition, refiners increased the complexity of their facilities. (I explain complexity at great length in the March 21, 2007, issue.) Increasing the complexity of existing facilities allows the refiners to process different types of crude oil more efficiently.

Although refining capacity did increase, it certainly hasn’t moved up by much. Total refining capacity is up roughly 13 percent since the end of 1999. And this is total operable capacity, not the actual amount of capacity that’s operating; because of maintenance, small fires and turnaround operations, actual operating capacity is typically lower that this chart suggests.  
Here’s another way to look at the same basic data:

Source: EIA

This chart shows US refinery utilization in percent terms. This is a measure of what percent of total US refinery capacity is being utilized at any given time. The higher the number, the harder refineries are being run.

Typically, utilization rates above 90 percent indicate a tight balance between capacity and demand. High utilization rates typically mean a strong environment for refiners.

What’s clear here is that utilization increased markedly from the mid-’80s through the end of the ’90s. Since then, utilization has remained at relatively high levels. This suggests the refining supply/demand balance has been generally favorable for the group.

However, there’s a strong case to be made that this tailwind is abating. The strengthening environment for refiners has encouraged these companies to invest in capacity expansions and upgrades. Refiners performed only basic maintenance work back in the ’90s because profitability for the group was so weak. Finally, as profitability recovered, firms gained enough confidence to invest in new capacity.

Here’s a rundown of some of the major refinery construction and expansion deals planned for the next few years:

Refining Construction Projects
Added Capacity (bbl/day)
Expected Completion
BP Coker 102,000 2011
BP Hydrotreater 105,000 2011
Chevron Coker 20,000 2007
ConocoPhillips Hydrotreater 3,000 2007
Flint Hills Resources Coker 2,000 2007
Holly Corp Hydrocracker 15,000 2008
Marathon Oil Corp Catalytic Reforming 65,000 2009
Marathon Oil Corp Crude Distillation 185,000 2009
Marathon Oil Corp Coker 44,000 2009
Marathon Oil Corp Distillate Upgrading 85,000 2009
Marathon Oil Corp Naptha Desulphurizing 40,000 2009
Marathon Oil Corp Straight Run Distillate 47,000 2009
Marathon Oil Corp Vacuum Distillation 100,000 2009
Motiva Enterprises Refinery Expansion 325,000 2010
Motiva Enterprises Coker 95,000 2010
Motiva Enterprises Hydrocracker 75,000 2010
Motiva Enterprises Hydrotreater 113,000 2010
Motiva Enterprises Hydrotreater 50,000 2010
Motiva Enterprises Isomerization 48,000 2010
Motiva Enterprises Reformer 85,000 2010
Navajo Refining Hydrocracker 15,000 2008
Placid Refining Desulphurization 18,000 2008
Sinclair Oil Refinery Expansion 45,000 2011
Sinclair Oil Coker 30,000 2009
Valero Energy Ultra Low Sulphur Diesel (ULSD) 16,000 2007
Valero Energy ULSD 55,000 2007
Valero Energy Hydrocracker 50,500 2007
Valero Energy Hydrocracker 57,000 2007
Wynnewood Hydrotreater 20,000 2007
Source: Oil & Gas Journal

This constitutes an ambitious list of new construction projects scheduled for completion between now and 2011. Of course, some of these projects will undoubtedly be delayed, while others may be canceled for one reason or another. The total capacity additions are likely to be somewhat less than this table suggests.

However, what’s clear is that US refining capacity is expanding and the market is likely to become less tight over the next few years. I’m not forecasting a collapse in margins and profitability for the group. Rather, I’m looking for a moderation in the refining environment.

Back to In This Issue

How to Play It

There are four stocks in the TES model portfolios with significant exposure to refining: Valero Energy, Chevron Corp, NuStar Energy and Dresser-Rand. In light of the current weak outlook for refining, here’s my take on each:

As noted above, Chevron Corp is a major integrated oil company that derives about a quarter of its profits from refining. Although the company will be negatively impacted by weaker refining margins, the company’s E&P business tends to drive the stock more than refining.

In that regard, Chevron remains among my favorites. As I highlighted in the Nov. 21, 2007, issue, Super Oil, Chevron has the best potential among the major integrated oil companies to show real oil and natural gas production growth in the next few years. The reason is Chevron has a number of major new projects slated to come on line over the next few years.

Although the company has since announced delays at five of its international projects, this is nothing unusual; big international projects are prone to delay. And at a recent analyst meeting, Chevron stated it still sees its total reserves growing about 5 percent between now and the end of 2010.

Total oil equivalent production should also increase from 2.62 million barrels per day last year to 2.92 million barrels per day in 2010. Most of that jump is because 11 projects are coming on line between now and 2010.

Few of the big integrated are showing any real production growth; in that regard, Chevron stands out. Chevron Corp remains a buy.

Valero Energy is my purest play on the refining industry; the company is the largest independent refiner in the US, with total refining capacity of 3.1 million barrels per day.

The investment case for Valero has changed little since the March 21, 2007, issue. The company benefits from among the strongest geographical positions of any refiner and some of the most highly complex refineries in the business.

Refining margins differ widely between different parts of the US.  For example, the West Coast and specific markets—such as Phoenix and Las Vegas—are chronically short of refining capacity. Margins tend to be higher in these regions than for the country as a whole. With exposure to almost every conceivable geographic region of the US, Valero is well placed to benefit from the tightest markets.

And different types of crude oil trade at different prices. West Texas Intermediate crude, the varietal that underlies the NYMEX futures contract, currently trades at more than $106 per barrel. Meanwhile, a higher sulphur, harder-to-refine Mexican crude known as Maya is trading at $86 per barrel.

Not all refiners can handle Maya crude, but those that can are able to purchase cheaper grades of crude for their refineries. This lowers feedstock costs and makes for higher profit margins than the simple crack spread suggests.

Finally, I firmly believe Valero’s new profit-focused strategy will benefit shareholders longer term. Until last year, Valero had been focused on acquisition-led growth; that made sense in a strengthening margin environment. Now, management has refocused on profitability, selling off underperforming, less-profitable refineries. And Valero is redeploying some of the cash proceeds from these sales to implement share buyback plans and invest in small expansion projects for existing operations.

However, although Valero is my favorite refiner long term, the stock has been hit by the unusually weak crack spread environment just like all the other refiners. My less-bullish, intermediate-term outlook for the group also has me worried about Valero. I’ve been holding on to the stock in the Wildcatters Portfolio in anticipation of a seasonal uptick in refining margins. To date, that seasonal move just hasn’t happened.

I expect at least a short-term spike higher in crack spreads at some point over the next month and a half. In any event, Valero is trading at an attractive enough valuation to keep value-oriented investors interested; I see a floor under the stock in the mid-$40s. I’m cutting Valero Energy to a hold this issue but will retain it in the Portfolio pending a potential crack spread spike.

NuStar Energy was formerly known as Valero LP; it’s a master limited partnership (MLP) that was originally set up to own refined product pipelines. MLPs are a special class of high-yielding, tax-advantaged securities. (I offer a detailed rundown of the group in the Nov. 22, 2006, issue, Leading Income.)

Refined products pipelines are among the most stable assets an MLP can own. Since the early ’80s, there have been only two times when refined product demand has dropped year-over-year in the US. Volumes tend to remain stable even during downturns. Because NuStar is paid solely on the volume of refined products transported, stable volume spells stable cash flows.

NuStar’s core pipes and terminals business is performing well. Demand for terminals is rising in the US; terminals are used to store and blend gasoline. Ethanol can’t be mixed with gasoline and transported through pipelines because of its corrosive nature. As a result, refiners are increasingly relying on NuStar to blend ethanol and gasoline at its terminal facilities. The MLP is paid extra fees for these services.

NuStar has spent $100 million in the past year on building out its terminal capacity and has plans for another $260 million in terminal expansion projects to come on line in 2008. Also, it acquired a major oil terminal facility in Louisiana last year and believes it has the scope to add more capacity to that facility to meet demand; the terminal is well placed to accept and process crude oil imports. In total, management has identified $500 million in new organic growth projects that could be completed in the next two to three years.

But late last year, the MLP announced a deal to buy two asphalt refineries along the East Coast from CITGO for $450 million. These refineries process heavy crude oil into asphalt and a handful of other asphalt-like products. That deal has proved highly controversial for two major reasons.

First, ownership of these refineries will expose NuStar to higher business risks. Refineries are exposed to the volatility of the crack spread, while refined product pipes aren’t.  

Second, part of the deal is an ongoing supply contract between CITGO and NuStar. This long-term deal will mean that Venezuela continues to supply heavy oil products to NuStar’s refineries. The fear here is that Venezuela could renege on that contract; the nation has threatened to slow exports of oil and oil products to the US on several occasions.

There are some factors that will help offset the risks of the CITGO deal. First, the company’s purchase price was favorable at roughly half of what it would cost to build these two refineries–with a total throughput of more than 100,000 barrels per day–from scratch. And NuStar’s management has said that it will only pay out about half of the distributable cash flow that the refineries generate. By retaining some cash, NuStar is