Super Oil
The big, integrated oil companies are the most recognizable faces of the energy industry. Every time gasoline prices rise above $3 in the US, it’s the CEOs of these firms who get dragged before Congress to explain what’s going on. Many seem to assume that it’s the Super Oils that control the global energy markets.
Of course, this is pure fantasy. The so-called Super Oils control only a tiny part of the world’s reserves of oil and natural gas.
Even worse, in recent years, state-owned national oil companies have been exerting more control and demanding better deals when partnering with Super Oil on important international projects. These integrateds are far from the monopolistic behemoths many suppose.
The integrateds have been among the most reliable stocks investors can own in the long run. Proven Reserves Portfolio recommendation Chevron Corp, for example, returned an average annualized 13.9 percent during the 1990s despite a bear market in oil and natural gas prices.
In this issue, we’ll take a closer look at the integrated oil industry, the current trends in the business and a few of our favorite stocks in the group.
Before I jump solely into the oil sector, I wanted to address the behavior in the general stock market of late. The credit crunch from this summer has affected all aspects of the market. This includes energy stocks, despite the prices of certain energy-related commodities. See Handling Volatility.
Despite the recognition these firms may receive worldwide, integrated oil companies are hardly monopolistic. These firms are really nothing more than companies engaged in some combination of two basic business lines. I explore these two lines below. See Major Integrated Oil Companies.
There are seven major integrated oil companies worth noting. I already hold two in the model portfolios, and I’ll continue to track two in the How They Rate Table to see how they progress. See How to Play Integrated Oil.
In this issue, I’m recommending or reiterating my recommendation on the following stocks:
Many of the world’s largest banks have been forced to write off billions in assets as they mark down the value of mortgage-backed securities and structured credit products held on their books. And valuing such assets effectively is nearly impossible because the market for such securities has dried up completely in recent months.
One of the surest signs of financial distress and contracting credit is a period of prolonged weakness in financial stocks. Check out the chart below.
Source: Bloomberg
This chart shows the relative performance of the S&P Financials Index against the broader S&P 500. A falling line indicates banks are underperforming the broader market. This trend has been going on since midyear.
The obvious fears remain that the weakening housing market will hit the American consumer hard and tip the US economy into recession next year. Moreover, there are concerns that a dried up credit market will impact corporations’ ability to invest and grow.
It may seem a bit off topic to start a discussion of global stock market performance and macroeconomics in an energy-focused newsletter. But it’s important to understand that no sector trades in a vacuum.
Energy-related stocks have handily outperformed the broader S&P 500 since the beginning of 2007, with the S&P 500 Energy Index up 24.6 percent against a 2.3 percent return for the S&P over the same time period. On a shorter-term basis, after rallying 19 percent from its August lows through mid-October, the index has since pulled back around 6.5 percent.
I’m often asked how energy stocks can be getting hit at all with oil near $100; certainly, oil near the century mark is a boon to many companies in the group. In the long run, fundamentals prevail. However, in the short term, the reality is that energy stocks are still stocks and all equities are, to at least some extent, influenced by the economic outlook and action in global stock markets.
Although I remain convinced that energy stocks are still in the early stages of a multiyear bull market that will bring tremendous gains, we can’t afford to ignore shorter-term trends. Every great bull market in history has seen corrections, sometimes of 30 percent or more, before ultimately rallying to new highs. In fact, such shakeouts and corrections historically bring the best opportunities for investors and should be welcomed as a chance to get into well-placed stocks at attractive prices.
Longtime subscribers know this isn’t the first correction we’ve seen in the energy patch or the first time The Energy Strategist portfolios have been impacted by traders’ rising risk aversion and fears of a global economic slowdown. The last such instance was the summer of 2006; that proved to be a truly epic buying opportunity.
The Philadelphia Oil Service Index and S&P 500 Energy Index are up an astounding 60 percent and 35 percent, respectively, since their October 2006 lows. And the model portfolios have handily outperformed their benchmarks since that time.
The bottom line is that investors shouldn’t be tempted to run for the hills and panic every time the market pulls back. We can continue to profit even during weak markets.
I see no reason to deviate from the strategies that have served us so well during prior corrections of the past few years. I advocate using a combination of the following strategies to protect our downside and prepare your portfolio for the inevitable next leg higher:
Partial and Outright Sales–During the past few months, I’ve recommended selling all or part of your position in some of the best-performing stocks in the portfolios. Partial sales are a particularly useful technique.
For example, if you have $15,000 invested in a stock and a $5,000 total profit, there’s no law that states you must sell your entire $15,000 stake. Instead, you can sell half your position, or $7,500.
Such a partial sale would lock in some of your gains and protect you in any pullback. But partial sales also leave you upside in the event the stock continues rallying. And you can always re-buy the stock you sold at more favorable prices down the road.
In the past three months, I’ve recommended selling out of Schlumberger and FMC Technologies to lock in substantial gains of 70 percent and 125 percent, respectively. And in the Sept. 15 issue of TES, Down on the Farm, I recommended booking partial gains in many of the biggest winners in the biofuels field bet.
In many cases, I recommended taking partial profits as these stocks rallied in a near parabolic fashion. And, of course, it’s always a good idea to trim the deadwood occasionally–selling stocks that just aren’t performing up to par or are facing new headwinds. For example, I recommended selling Carbo Ceramics in the Nov. 7 issue of TES, Coal and Services, for a small loss given the weakening trends I’ve been seeing in the pressure pumping market.
Stop Order Recommendations–A stop order is simply an order you leave with you broker to sell you out of a stock at a predetermined “stop” price. In other words, if you buy a stock at $100 and set a stop at $90, your broker will sell your position as soon as the stock trades at $90. This would serve to limit your loss on the stock. This is also why stops are sometime called “stop losses.”
But stops aren’t just for protecting your downside and limiting losses. They’re also a valuable way to lock in gains. The best way to illustrate is with an example.
Assume you buy a stock at $100, and it rallies all the way to $150. It’s unlikely you’re willing to risk losing that entire $50 profit; at the same time, you may think there’s more upside to come.
One strategy would be to place a stop at $130. This would effectively lock in a $30 profit. If the stock sold off back to $130, you’d be automatically sold out for a gain. But if the stock carried on moving higher, the stop would have no effect on your position and you’d still be participating in all the upside.
I also use stops as a trigger to re-evaluate positions. When we’re stopped out of a position, I always go back and take an even more careful look at the company; if I decide it’s still a good buy, I’ll recommend re-entering.
With commissions as low as they are these days, there’s absolutely no reason we can’t jump right back into good stocks. Such was the case with Peabody Coal last summer and Linn Energy last week.
I update my stop recommendations in the portfolio tables on an ongoing basis. Be sure to check back regularly for changes. I recommend at least reviewing the stops on each issue date.
Options Strategies–There are a number of options strategies we can use to lock in gains on big winners without sacrificing upside. I highlighted my two favorites in the Feb. 21 issue of TES, All Eyes on Gas. (See the subsection “Inevitable Corrections.”) In the subsection Major Integrated Oil Companies below, I offer some specific options recommendations to hedge current TES picks.
Do not be put off by the word “options.” Options can be used for speculation, but they can just as easily be used to reduce risk.
Outright Short Positions–During market downturns, we don’t need to focus solely on not losing money and protecting gains; short selling also allows us to actually profit from downside in stocks.
In the Nov. 12 flash alert, I recommended shorting Halliburton or, for those unwilling to short, buying the April 2008 $40 put options (HAL PH) on the stock. I offer a detailed guide on shorting and put buying in the June 14, 2006, issue of TES, The Good, The Bad, The Ugly. (See the subsection “Pair Trades, Shorts and Puts.”)
Back to In This Issue
If you don’t believe me, just examine the facts. The two largest integrated oil companies in the world outside the largely state-owned national oil companies are ExxonMobil and Chevron. Together these firms produce exactly 5.4 percent of the world’s oil and 5.7 percent of the world’s natural gas–hardly a monopoly position.
Integrated oils are really nothing more than companies engaged in some combination of two basic business lines: exploration and production (E&P) and refining and marketing (R&M). Analyzing these firms from an investment standpoint requires understanding the relative exposure each firm has to these two lines.
Before looking at specifics, it’s important to understand both the E&P and R&M businesses and the current outlook for each. Here’s a quick rundown.
E&P
The E&P business is far and away the most important for the integrated oil companies. On average, this business segment, often called upstream operations, accounts for around 70 percent of the profits of the big oil companies.
The E&P industry is also among the simplest to understand in the oil and gas business: E&P companies look for, develop, produce and sell hydrocarbons. There’s little difference between the basic E&P business of the integrated companies and their smaller E&P cousins, such as Wildcatters Portfolio members EOG Resources and XTO Energy and Gushers Portfolio recommendation Quicksilver Resources.
The only real difference is in the type of reserves targeted. Integrated oil companies tend to pursue major, multiyear projects such as deepwater developments or international projects. In many cases, integrated oil companies will partner with state-owned (or partly state-owned) national oil companies (NOC), such as Brazil’s Petrobras, to develop certain fields.
In these deals, the oil majors typically supply the know-how and technology; in exchange, the integrateds usually receive some preset portion of revenues arising from the sale of oil and gas produced. Such arrangements are dubbed production sharing contracts (PSC).
Integrated oil companies have the advantage of size and experience. These companies have the size and financial resources to spend the billions required to bring a deepwater project online or handle the drilling of complex wells that can take months to drill. They also have the scale to drill exploratory wells offshore or undertake massive seismic shoots to try to pinpoint big new potential reserves in new exploration hot spots such as the deepwater or Artic.
Smaller E&P firms, in contrast, typically target smaller projects and, in many cases, less risky drilling plans. EOG, Quicksilver and XTO, for example, all have land in the Barnett Shale of Texas, a gas reserve that’s well understood and explored. Their production growth comes from simply drilling more wells, more efficiently in this region and optimizing production from those wells.
Despite this important distinction, I look at the same basic fundamental factors when evaluation the E&P business of the integrated oils as I do when examining the smaller, independent E&Ps. The prime factors to consider are production mix between oil and gas, commodity prices, production costs and production growth potential.
A common misconception is that you can simply look at the price of oil and immediately determine how profitable the E&P segments of the major oil companies will be. It’s far more complicated than that.
The easiest way to explain is to look at an example and examine all the moving parts. Let’s take ExxonMobil’s third quarter earnings report. In the third quarter of 2007, Exxon’s upstream (E&P) earnings fell $194 million against the same quarter one year ago. That isn’t a misprint; upstream earnings declined despite near $100 oil.
On the upside, ExxonMobil benefited from higher realizations year-over-year. The term realization refers to the prices the company was able to get for its crude oil and natural gas production.
In this case, the rally in crude oil helped push Exxon’s realization from $65.14 per barrel in the year-ago period to about $71.46 in the third quarter this year. The total effect of realizations was a $630 million benefit to the bottom line.
Of course, $71.46 is a far cry from current oil prices above $90 you hear quoted on the evening news. But that’s not really surprising; the typical crude oil prices you hear quoted are West Texas Intermediate and Brent crudes, some of the most expensive grades of crude in the world. The price of lesser grades—such as heavy or sour crudes—is far below the price of these benchmarks.
If you’re unfamiliar with the concept of different grades of crude, check out the March 21 issue of TES, Looking Refined.
Another positive factor for the upstream business was a category that ExxonMobil calls volume/mix. Volume refers to the total volume of hydrocarbons that the company produces in a year. If we exclude the impact of some extraordinary issues that I’ll detail in a moment, Exxon’s production volume rose about 3 percent in oil equivalent terms.
Offsetting that was a poorer mix of production. This means Exxon produced more natural gas relative to oil this year than it did a year ago. Because global natural gas prices have been flat or declining over the past year, this is negative for the company’s bottom line. Overall, however, Exxon’s volume and mix added a small $20 million benefit compared to last year.
Offsetting the $650 million benefit of realizations, volume and mix were a number of key negatives. The most important of these is that Exxon didn’t see an actual increase in production.
Recall that Exxon reported a 3 percent increase in oil equivalent volumes after accounting for certain extraordinary items; if we don’t exclude those items, production declined 2 percent. Here’s a rundown of those major factors:
PSCs–First, as noted above, many of Exxon’s production agreements with NOCs involve PSCs. Every PSC is a bit different, but most involve some clauses related to commodity prices and cost recovery. The basic effect of these clauses is that, at higher oil and gas prices, the integrated oil firm gets a smaller share of production from the project.
The idea is that NOCs want to allow the integrated oil companies (IOC) to recover their costs. Therefore, up to a certain production level, the IOCs get a higher share of the production. After that cost is recovered, the NOCs step-up their share of the production and profits. In addition, many NOCs negotiate contracts so that they can participate more in commodity price upside.
This is exactly what happened to Exxon. Lower entitlements under PSCs because of high energy costs accounted for about 3.5 percent lower production overall.
Venezuela–Venezuelan President Hugo Chavez has made little secret of his disdain for PSC deals with the big, multinational IOCs. He’s also continued to pursue a plan of re-nationalizing the country’s energy sector.
Part of this trend was the Chavez government’s decision to unilaterally change the agreements governing heavy oil projects in the nation by seizing at least a 60 percent share of these deals. Exxon and ConocoPhillips were unable to reach an agreement with the Venezuelan government in June and exited operations in the nation. Other companies, including Chevron, did renegotiate deals and decided to remain in Venezuela. The decision to exit Venezuela cost Exxon about 1 percent of volumes year-over-year.
The nationalization of energy projects in Venezuela has grabbed the headlines, but the situation there isn’t totally unique. In fact, Venezuela highlights a broader problem of resource access: With commodity prices on the rise, governments the world over are taking steps to renegotiate existing PSC deals or are forcibly trying to grab more control. This is a major ongoing headwind for the industry.
Divestments–The final and smallest piece of Exxon’s volume decline was simply divestments of certain assets. Basically, the company sold various fields around the world; the loss of that production hit volumes. This had about a 0.5 percent impact on volumes.
Exxon’s third quarter earnings release highlights some of the complications involved in evaluating the E&P businesses of the major integrated names. What I tend to look for in evaluating production growth potential is the lineup of projects scheduled over the next few years.
Because IOCs tend to pursue longer-term projects, we have a decent idea of what’s in store over the next few years; although there are often delays, I tend to prefer companies with big projects scheduled for completion near term.
Of course, the E&P business of integrateds does, by its very definition, have significant leverage to commodity prices. As you can clearly see from the Exxon example outlined above, realizations were the most important year-over-year impact to the bottom line.
Although realizations are currently a big positive, inevitable pullbacks in oil and gas prices can quickly turn into a headwind for IOCs. That’s why production growth and new product startups are so important; IOCs can make up somewhat for weak commodity prices by bringing more volume online. Over the long term, E&P companies and integrateds showing the most volume growth tend to outperform.
R&M
Refining is perhaps the most poorly understood area of the energy business. Back in October, several of the big IOCs warmed on their third quarter earnings. I received no fewer than five requests for radio and television interviews to explain how oil could be at $100 and these companies could be reporting weak numbers. The media unfailingly focuses on the E&P business–where $100 oil is a benefit–at the expense of refining.
R&M is that missing link. I’ve explained this phenomenon before at some length, most recently in the March 21 issue of TES.
To summarize, refiners don’t make money by selling crude oil. These firms actually buy crude oil and sell refined products like gasoline and heating oil.
Therefore, refiners make money based on the spread between the cost of oil and that of refined products. If the value of refined products increases faster than the cost of crude oil, refining margins expand and companies make more money in R&M.
But in the third quarter of this year, the opposite happened. The cost of crude oil actually rose faster than the value of refined products; these companies actually saw their refining margins shrink notably. In most cases it was R&M, not E&P, which prompted profit warnings in October.
A very useful quick-and-dirty measure of refining margins 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. This measures the refining profit per barrel of converting three barrels of crude oil into two barrels of gasoline and one barrel of heating oil. Here’s a chart of the 3-2-1 crack spread in the past several months.
Source: Bloomberg
The trend here is clear. After spiking to more than $30 per barrel in May, the crack spread went under $5 per barrel in October. The big run-up in crack spreads in the first and second quarters was due to a series of refinery problems all around the US. These outages meant that refiners struggled to produce enough gasoline to cover the US summer driving season. Meanwhile, US crude oil inventories were usually high because refiners simply weren’t converting that crude to gasoline.
The result: The supply overhang of high crude inventories put a cap on crude prices. Meanwhile shortages of gasoline and refining capacity pushed up gasoline prices. Refining margins truly exploded.
But refining margins subsequently collapsed in late summer after the peak of summer driving season. The primary driver was the rise in crude oil prices; higher crude oil prices depress refining margins for the reasons I noted earlier. Gasoline prices just haven’t risen quickly enough to offset this crude oil rally.
But much of this refining margin effect is seasonal. It’s certainly nothing unique to 2007. The chart below shows the 3-2-1 crack spread on May 1 and the last trading day of October for each year from 2003 to 2007.
Source: Bloomberg
This chart shows that, in every year since 2003, the crack spread has declined between May 1 and Oct. 31. This is mainly the simple consequence of refiners gearing up for the summer driving season during the spring and early summer; they use the third quarter, after the peak of driving season, as a time to perform maintenance on their facilities.
Also note that this seasonal effect is normally quite severe. The smallest seasonal decline in the chart was in 2005. But recall that was the year the a series of hurricanes hit Gulf Coast refining operations; this took a large amount of US refining capacity offline and sent refining margins sky-rocketing during a time of year when margins are typically weak. In every other year, the seasonal effect was pronounced.
I don’t see anything to be concerned about by the fact that third quarter R&M margins fell this year. The decline was dramatic only because margins spiked to unusually high levels in the spring.
Moreover, we’re already seeing a recovery in crack spreads, and I’m looking for margins to improve dramatically in the first half of 2008 as well. See the chart “Crack Spread Positive Seasonality” for a closer look.
Source: Bloomberg
This chart illustrates the crack spread from Jan. 1 to May 1 of each year going back to 2003. As you can see, the seasonal effect in crack spreads is positive in the first five months of each year. That’s because this is when refiners gear up their operations ahead of the summer driving season.
Bottom line: The headwinds in US refining margins that most IOCs reported in the third quarter should reverse into the first and second quarter of 2008.
I also expect a larger-than-normal run-up in margins in the first half of next year. The reason is that US gasoline inventories remain far lower than normal right now; see the chart below.
Source: Bloomberg
As refiners gear up their operations next year for the 2008 summer driving season, they’ll be fighting to bring those gasoline inventories back to more normal levels. That means running refineries full-bore, which raises the odds we’ll see more refining accidents that take capacity offline.
In addition, don’t forget the current situation in the crude oil markets: High crude oil prices are having a negative impact on refining margins right now. I’ve heard a large number of explanations for crude oil nearing $100, but most of those theories are complete bunk. The reality is that crude oil’s rise has very little to do with futures speculation, hedge funds or geopolitical uncertainty and very much to do with the current tight supply/demand balance.
Consider the most recent data for the International Energy Agency (IEA) on crude oil stocks in the Organization for Economic Cooperation and Development (OECD) countries. OECD countries are a good proxy for crude oil stocks in the developed world. Check out the chart below for a closer look at OECD oil inventories.
Source: IEA Oil Market Report
There are a few key points to note about this chart. The first is that I’ve labeled the third quarter of each year as a red bar.
Note that at the end of the third quarter, OECD inventories of crude were considerably lower than a year ago and actually lower than in 2005. Therefore, across the OECD, the supply of crude is tighter than it has been at this time of year since 2004.
Also note the typical change in OECD inventories between the second quarter and third quarter of each year. In a normal year, crude oil stocks actually rise between the end of the second quarter and the end of the third quarter. This corresponds to the end of the summer driving season in the Northern Hemisphere.
Note, however, that there was actually a fall in OECD crude oil inventories in the third quarter this year. Stocks of crude fell approximately 360,000 barrels per day in the fourth quarter, a counter-seasonal crude oil drawdown. That continued into October; early IEA estimates show a further 21-million-barrel draw in the month for OECD countries.
Although US oil inventories remain above average for this time of year, inventories did decline in the third quarter. That’s certainly not the normal seasonal pattern. And we can’t focus solely on the US; oil inventories in Japan, for example, currently stand at their lowest level in at least 20 years.
There are two factors underpinning these inventory draws. First, it appears that the Organization of the Petroleum Exporting Countries (OPEC) isn’t exporting as much oil as it normally would at this time of the year. And second, non-OPEC production growth remains problematic because of faster-than-expected declines in existing field production and a series of project startup delays.
The easiest way to measure the availability of OPEC supply is to look at tanker rates. Check out the chart below for a closer look.
Source: Bloomberg
Recall that tanker charter rates don’t follow the path of crude oil. Tankers don’t make money based on the value of crude oil they ship. In fact, when OPEC is very actively boosting output, that’s great news for tanker rates because it means more product can be carried. Therefore, in periods of strong OPEC supply growth, tanker rates will normally spike as demand exceeds available supply.
This is why you see those prominent “spikes” on the chart of the Baltic Dirty Index of tanker rates above. These spikes tend to occur in the fourth quarter of each year as refiners step up their oil imports to refill inventories.
Although tanker rates have risen somewhat lately, the effect is far less pronounced than it normally would be for this time of the year. This reflects the fact that there are large numbers of idle tankers in the Middle East waiting for shipments. That reflects the fact that there simply isn’t enough oil headed to the US from the Middle East.
Here’s my take on the crude oil market: I’m looking for continued supply tightness into year-end. Over this period, it’s quite possible we could see a spike to more than $100 per barrel, especially if any new non-OPEC projects are delayed. Alternatively, further OPEC rhetoric indicating limited upside to supply, such as we heard over the weekend, could catalyze a spike in crude.
Going into 2008, however, I expect two factors to moderate oil prices. First, I expect OPEC will eventually ship more oil and we’ll see those tanker rates spike somewhat. And second, the IEA offered some tentative signs of demand destruction in its most recent report: Higher oil and refined product prices have started to impact consumers’ demand for crude oil.
The IEA revised 2008 oil demand growth lower by a modest 300,000 barrels per day. Given the obvious weakening in the US economy and the growth scare I outlined at the beginning of this issue, investors are bound to start pricing in a more meaningful decline in demand.
Note I’m not looking for a collapse in oil prices as some bears have been projecting. I’m instead looking for a potential decline to the $70-to-$80-per-barrel range at a maximum.
I always get a kick out of these articles in the major print media that appear every few months, predicting a major decline in oil prices. Remember, most oil bears have been recycling the same arguments about unsustainable geopolitical risk premiums and excess speculation for years.
But the reality is that geopolitical risk is a more or less permanent feature of the global crude oil markets. I just don’t see the US, the EU, Iran and Venezuela deciding to become fast friends overnight.
And I can recall many using the same excess speculation arguments to predict a drop in oil prices below $40 per barrel at the beginning of 2007. The fact is that the unwinding of speculative trades can have an impact on prices in the short run.
In the long run, prices are determined by actual supply and demand. On that front, increased crude oil demand will remain strong in coming years because of strong growth from the emerging markets such as China and India.
Meanwhile, supply growth remains troubled. OPEC’s actual spare capacity—production that can be brought online quickly and sustained—has been falling steadily in recent years. And growth in oil production outside OPEC has consistently undercut expectations.
This is all part of the “End of East Oil” thesis I’ve outlined on numerous occasions in TES. Basically, large onshore fields have become largely depleted and are seeing rapid declines in output. Meanwhile, producers are increasingly targeting more complex reserves such as those in deepwater and the Artic.
Ramping up such complex projects is fraught with difficulty. For example, we’ve all heard about Brazil’s recently discovered Tupi field in the deepwater; this field is among the largest discoveries in recent years.
But what many haven’t heard is just how complex this field is. The Tupi field is located in water 6,000 feet deep and a further 15,000 feet under the seafloor. There’s also a 6,000-foot-deep salt layer to drill through to access this field.
Developing Tupi will involve drilling some of the most complex wells in history. And drilling these wells will require access to advanced deepwater drilling rigs and some complex infrastructure, services and equipment. Given the shortages in the industry, that means at least a five-to-10-year wait for production from this field.
Bottom line: I expect refining margins to expand in the first part of 2008 amid a modest decline in crude oil prices and a seasonal ramp in refining activity. Longer term, I see a continued tight supply/demand balance for crude that will keep prices elevated for years to come.
Back to In This Issue
Source: Bloomberg, company accounts
This table includes what I regard to be some of the most important metrics to watch for IOCs. Most of the table columns are self-explanatory. Two that are less familiar are Price/BOE and Reserve Replacement.
The first is a valuation measure. Essentially, it’s calculated by dividing an integrated’s total market value by the company’s total reserves of oil and natural gas on a barrel of oil equivalent (boe) basis. The higher the number, the more you’re paying for the company’s reserves and the more richly valued the firm is.
The reserve replacement figure simply compares the amount of new oil and gas fields a company discovers or acquires to that firm’s production. Numbers above 100 percent indicate that the company is booking more new reserves that it’s producing; it’s essentially replacing the reserves it produces each year. To make a long story short, the higher this number, the better.
I recommend two of the companies on this list—ExxonMobil Corp and Chevron Corp—both in the income-oriented Proven Reserves Portfolio. However, as of this issue, I recommend selling ExxonMobil Corp for a total profit of close to 60 percent over a roughly two-year holding period; I’ll continue to track it in the How They Rate Table.
When I originally recommended this stock, Exxon had been hit by general weakness in the energy patch and was trading at an attractive valuation. I felt that Exxon was a defensive way to add exposure to a rebound in the energy space.
Although the recommendation has worked out well, my original reasons for buying the stock no longer apply. I don’t think it’s a bad company to own, but I do see several more attractive destinations for your investment dollars.
Note, in particular, that on a Price/BOE, Price-to-Earnings and Price-to-Cash-Flow basis, Exxon is either the most expensive or among the most expensive stocks in the table. Although I can accept some premium because of Exxon’s enormous size and long track record of performance, this degree of valuation premium looks unwarranted.
And Exxon isn’t expected to show much production growth over the next few years. Consensus analyst expectations are for Exxon to show overall production growth of just more than 1 percent annualized through the end of 2010.
Most of that growth is expected to be in the form of higher natural gas production rather than crude oil. In particular, Exxon is looking for considerable growth from its natural gas projects on Qatar. See the map of the Middle East below for a better idea of where Qatar is.
Source: Google
Qatar has the world’s third-largest gas reserves. Better still, Qatar’s fields represent some of the lowest production cost reserves in the world.
The country plans to develop these reserves using a mixture of liquefied natural gas (LNG) and gas-to-liquids (GTL) technologies. (See the April 12, 2006, issue, Finding New Btus, and the Oct. 24 issue, Liquid Gold, for a more-thorough explanation of both technologies.)
According to Exxon, Qatar will be the world’s most important exporter of LNG by 2015. The nation will move from exporting about 25 million tons of gas per year in 2006 to closer to 80 million tons in 2015.
ExxonMobil has stakes in several LNG projects in Qatar; during the next two years, these projects are scheduled to start up and begin shipping LNG. This is behind a good chunk of Exxon’s gas production growth.
Nonetheless, growth in countries such as Qatar will likely just offset natural declines in production from existing fields and existing projects, leaving the company’s total growth roughly flat. Although Exxon’s projects are certainly attractive, world-class opportunities, I’m just don’t view that level of growth as anything exciting. That’s especially true when you consider that the stock is so much more expensive on a valuation basis that its peer group.
Chevron remains my favorite among the US IOCs. In contrast to Exxon, it appears relatively cheap in all three valuation measures quoted in the table–price-to-BOE, price-to-earnings and price-to-cash-flow.
In addition, the company offers a superior dividend yield to Exxon. Although a 2.7 percent yield doesn’t exactly make Chevron an income stock, it’s consistently boosted that payout over time by more than 10 percent annualized over the past five years.
Chevron is also one of the only Super Oils that will show meaningful growth in production over the coming few years. Even more important, it’s scheduled to start up four major projects over just the next two years that will generate significant production growth upside near term. Here’s a quick rundown:
Tahiti–Tahiti is a deepwater field in the Gulf of Mexico where Chevron holds a 58 percent stake. The field is expected to have a peak production rate of 125,000 barrels of oil per day and 70 million cubic feet of natural gas.
Chevron has completed five of the six wells it’s scheduled to drill in this field and has built the pipelines that will carry production to shore. The company also has completed a significant amount of the subsea infrastructure associated with the field.
The Tahiti project was delayed earlier this year because of some problems with parts on the floating production platform that will be used to handle production associated with this field. These giant offshore platforms aren’t simple construction projects, and there are a lot of things that can potentially go wrong logistically.
The delay caused by these construction problems isn’t a huge surprise. Chevron is now on track to begin actual production in the third quarter of 2009.
Blind Faith–Blind Faith is another deepwater development in the Gulf where Chevron has a 75 percent interest. All three development wells originally associated with this project are complete. But the results were positive, so Chevron now has plans to drill a fourth well next year.
With the production platform and subsea infrastructure also nearing completion, Chevron expects Blind Faith production to begin in the second quarter of 2008. Total peak production from the field will be about 45,000 barrels of oil per day and 45 million cubic feet of natural gas.
Agbami–Agbami is a deepwater development offshore Nigeria in western Africa. The floating production storage and offloading (FPSO) platform associated with this field is complete and left the shipyard in Korea to be towed to Nigeria. Management believes the platform will be in place sometime in the first quarter of 2008.
This platform’s completion is a big positive. As Chevron pointed out in its recent conference call, this platform is the largest of its kind in the world. It is capable of processing 250,000 barrels of oil per day and storing more than 2 million barrels.
Chevron has also completed 18 wells associated with Agbami and should begin production by the third quarter of 2008, with production ramping up to full capacity—250,000 barrels per day–within one year. Chevron has a 68 percent interest in the field.
Tengiz–Finally, there’s the Tengiz field located in Kazakhstan. This isn’t a totally new project; it’s simply the expansion of an existing production facility. What Chevron plans to do is to inject sour natural gas—gas with high-sulphur content—back into the Tengiz oil field.
Injecting this gas will help to repressurize the field and increase production from the field. When Tengiz was first tapped, the underground pressure was around 12,000 pounds per square inch (psi), but that’s now down to 8,500 psi in many parts of the field.
This has resulted in high decline rate in terms of actual oil production volumes. Chevron’s project here—where it has a 50 percent interest—would help to reverse that decline rate.
First oil production should begin this quarter and add another 90,000 barrels per day. A second phase of the deal is scheduled for completion in the second half of next year and will add a further 160,000 barrels per day.
As you can see, many of these projects are actually scheduled for startup next year. There’s significant scope for Chevron to generate real oil production growth in 2008.
And it’s worth noting that Chevron reported that the decline rate at its exiting fields has slowed significantly of late. If that trend continues as new projects start up, it could offer even more upside to production volumes.
All told, Chevron’s share of production from these four new projects is more than 400,000 barrels of oil per day worth of production. When you consider that Chevron currently produces about 2.6 million barrels of oil equivalent per day, these projects represent 15 percent of the company’s total production.
In addition to these near-term projects, Chevron has an impressive backlog of projects that are somewhat further from completion. An example of this is the massive Gorgon LNG project in Australia.
This project off the coast of western Australia is the largest ever conducted in that nation. Back in October, the Australian government gave Chevron and the other Gorgon partners the go-ahead. Chevron Corp rates a buy.
I’m also looking seriously at some of the other integrateds on the table. Specifically, Italy’s ENI looks attractive from a valuation standpoint and offers a healthy 5 percent dividend yield.
Eni has a large European natural gas business. Gas demand in Europe is set to soar in coming years. I also like ENI’s portfolio of new oil projects as a source of production growth upside.
I regard this business as highly attractive longer term. I’ll track ENI in the How They Rate Table with the possibility of adding it to the model portfolios in the near future.
ConocoPhillips is also an interesting growth story. In particular, Conoco remains an excellent way to play growth in Russia; the firm has a 20 percent stake in Lukoil. I’ll also track ConocoPhillips in How They Rate Table.
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Of course, this is pure fantasy. The so-called Super Oils control only a tiny part of the world’s reserves of oil and natural gas.
Even worse, in recent years, state-owned national oil companies have been exerting more control and demanding better deals when partnering with Super Oil on important international projects. These integrateds are far from the monopolistic behemoths many suppose.
In This Issue
What the integrateds do offer is relative safety and stability. Most have been paying dividends for many years, and the classic business model of Super Oil–a combination of refining and production–offers some natural hedges against commodity prices.The integrateds have been among the most reliable stocks investors can own in the long run. Proven Reserves Portfolio recommendation Chevron Corp, for example, returned an average annualized 13.9 percent during the 1990s despite a bear market in oil and natural gas prices.
In this issue, we’ll take a closer look at the integrated oil industry, the current trends in the business and a few of our favorite stocks in the group.
Before I jump solely into the oil sector, I wanted to address the behavior in the general stock market of late. The credit crunch from this summer has affected all aspects of the market. This includes energy stocks, despite the prices of certain energy-related commodities. See Handling Volatility.
Despite the recognition these firms may receive worldwide, integrated oil companies are hardly monopolistic. These firms are really nothing more than companies engaged in some combination of two basic business lines. I explore these two lines below. See Major Integrated Oil Companies.
There are seven major integrated oil companies worth noting. I already hold two in the model portfolios, and I’ll continue to track two in the How They Rate Table to see how they progress. See How to Play Integrated Oil.
In this issue, I’m recommending or reiterating my recommendation on the following stocks:
- Chevron Corp (NYSE: CVX)
- ConocoPhillips (NYSE: COP)
- ENI (NYSE: E, Italy: ENI)
- ExxonMobil Corp (NYSE: XOM)
Handling Volatility
Global markets are currently in the grips of a classic growth scare. The severe downturn in the US housing market has led to rising default rates on residential mortgages and sparked a global credit crunch.Many of the world’s largest banks have been forced to write off billions in assets as they mark down the value of mortgage-backed securities and structured credit products held on their books. And valuing such assets effectively is nearly impossible because the market for such securities has dried up completely in recent months.
One of the surest signs of financial distress and contracting credit is a period of prolonged weakness in financial stocks. Check out the chart below.
Source: Bloomberg
This chart shows the relative performance of the S&P Financials Index against the broader S&P 500. A falling line indicates banks are underperforming the broader market. This trend has been going on since midyear.
The obvious fears remain that the weakening housing market will hit the American consumer hard and tip the US economy into recession next year. Moreover, there are concerns that a dried up credit market will impact corporations’ ability to invest and grow.
It may seem a bit off topic to start a discussion of global stock market performance and macroeconomics in an energy-focused newsletter. But it’s important to understand that no sector trades in a vacuum.
Energy-related stocks have handily outperformed the broader S&P 500 since the beginning of 2007, with the S&P 500 Energy Index up 24.6 percent against a 2.3 percent return for the S&P over the same time period. On a shorter-term basis, after rallying 19 percent from its August lows through mid-October, the index has since pulled back around 6.5 percent.
I’m often asked how energy stocks can be getting hit at all with oil near $100; certainly, oil near the century mark is a boon to many companies in the group. In the long run, fundamentals prevail. However, in the short term, the reality is that energy stocks are still stocks and all equities are, to at least some extent, influenced by the economic outlook and action in global stock markets.
Although I remain convinced that energy stocks are still in the early stages of a multiyear bull market that will bring tremendous gains, we can’t afford to ignore shorter-term trends. Every great bull market in history has seen corrections, sometimes of 30 percent or more, before ultimately rallying to new highs. In fact, such shakeouts and corrections historically bring the best opportunities for investors and should be welcomed as a chance to get into well-placed stocks at attractive prices.
Longtime subscribers know this isn’t the first correction we’ve seen in the energy patch or the first time The Energy Strategist portfolios have been impacted by traders’ rising risk aversion and fears of a global economic slowdown. The last such instance was the summer of 2006; that proved to be a truly epic buying opportunity.
The Philadelphia Oil Service Index and S&P 500 Energy Index are up an astounding 60 percent and 35 percent, respectively, since their October 2006 lows. And the model portfolios have handily outperformed their benchmarks since that time.
The bottom line is that investors shouldn’t be tempted to run for the hills and panic every time the market pulls back. We can continue to profit even during weak markets.
I see no reason to deviate from the strategies that have served us so well during prior corrections of the past few years. I advocate using a combination of the following strategies to protect our downside and prepare your portfolio for the inevitable next leg higher:
Partial and Outright Sales–During the past few months, I’ve recommended selling all or part of your position in some of the best-performing stocks in the portfolios. Partial sales are a particularly useful technique.
For example, if you have $15,000 invested in a stock and a $5,000 total profit, there’s no law that states you must sell your entire $15,000 stake. Instead, you can sell half your position, or $7,500.
Such a partial sale would lock in some of your gains and protect you in any pullback. But partial sales also leave you upside in the event the stock continues rallying. And you can always re-buy the stock you sold at more favorable prices down the road.
In the past three months, I’ve recommended selling out of Schlumberger and FMC Technologies to lock in substantial gains of 70 percent and 125 percent, respectively. And in the Sept. 15 issue of TES, Down on the Farm, I recommended booking partial gains in many of the biggest winners in the biofuels field bet.
In many cases, I recommended taking partial profits as these stocks rallied in a near parabolic fashion. And, of course, it’s always a good idea to trim the deadwood occasionally–selling stocks that just aren’t performing up to par or are facing new headwinds. For example, I recommended selling Carbo Ceramics in the Nov. 7 issue of TES, Coal and Services, for a small loss given the weakening trends I’ve been seeing in the pressure pumping market.
Stop Order Recommendations–A stop order is simply an order you leave with you broker to sell you out of a stock at a predetermined “stop” price. In other words, if you buy a stock at $100 and set a stop at $90, your broker will sell your position as soon as the stock trades at $90. This would serve to limit your loss on the stock. This is also why stops are sometime called “stop losses.”
But stops aren’t just for protecting your downside and limiting losses. They’re also a valuable way to lock in gains. The best way to illustrate is with an example.
Assume you buy a stock at $100, and it rallies all the way to $150. It’s unlikely you’re willing to risk losing that entire $50 profit; at the same time, you may think there’s more upside to come.
One strategy would be to place a stop at $130. This would effectively lock in a $30 profit. If the stock sold off back to $130, you’d be automatically sold out for a gain. But if the stock carried on moving higher, the stop would have no effect on your position and you’d still be participating in all the upside.
I also use stops as a trigger to re-evaluate positions. When we’re stopped out of a position, I always go back and take an even more careful look at the company; if I decide it’s still a good buy, I’ll recommend re-entering.
With commissions as low as they are these days, there’s absolutely no reason we can’t jump right back into good stocks. Such was the case with Peabody Coal last summer and Linn Energy last week.
I update my stop recommendations in the portfolio tables on an ongoing basis. Be sure to check back regularly for changes. I recommend at least reviewing the stops on each issue date.
Options Strategies–There are a number of options strategies we can use to lock in gains on big winners without sacrificing upside. I highlighted my two favorites in the Feb. 21 issue of TES, All Eyes on Gas. (See the subsection “Inevitable Corrections.”) In the subsection Major Integrated Oil Companies below, I offer some specific options recommendations to hedge current TES picks.
Do not be put off by the word “options.” Options can be used for speculation, but they can just as easily be used to reduce risk.
Outright Short Positions–During market downturns, we don’t need to focus solely on not losing money and protecting gains; short selling also allows us to actually profit from downside in stocks.
In the Nov. 12 flash alert, I recommended shorting Halliburton or, for those unwilling to short, buying the April 2008 $40 put options (HAL PH) on the stock. I offer a detailed guide on shorting and put buying in the June 14, 2006, issue of TES, The Good, The Bad, The Ugly. (See the subsection “Pair Trades, Shorts and Puts.”)
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Major Integrated Oil Companies
Despite what you may have heard in the popular press, there’s nothing magical about big integrated oil companies such as ExxonMobil Corp and Chevron Corp. These firms aren’t endowed with some unique money-making machine, nor do they have any control whatsoever over the price or supply of oil or natural gas.If you don’t believe me, just examine the facts. The two largest integrated oil companies in the world outside the largely state-owned national oil companies are ExxonMobil and Chevron. Together these firms produce exactly 5.4 percent of the world’s oil and 5.7 percent of the world’s natural gas–hardly a monopoly position.
Integrated oils are really nothing more than companies engaged in some combination of two basic business lines: exploration and production (E&P) and refining and marketing (R&M). Analyzing these firms from an investment standpoint requires understanding the relative exposure each firm has to these two lines.
Before looking at specifics, it’s important to understand both the E&P and R&M businesses and the current outlook for each. Here’s a quick rundown.
E&P
The E&P business is far and away the most important for the integrated oil companies. On average, this business segment, often called upstream operations, accounts for around 70 percent of the profits of the big oil companies.
The E&P industry is also among the simplest to understand in the oil and gas business: E&P companies look for, develop, produce and sell hydrocarbons. There’s little difference between the basic E&P business of the integrated companies and their smaller E&P cousins, such as Wildcatters Portfolio members EOG Resources and XTO Energy and Gushers Portfolio recommendation Quicksilver Resources.
The only real difference is in the type of reserves targeted. Integrated oil companies tend to pursue major, multiyear projects such as deepwater developments or international projects. In many cases, integrated oil companies will partner with state-owned (or partly state-owned) national oil companies (NOC), such as Brazil’s Petrobras, to develop certain fields.
In these deals, the oil majors typically supply the know-how and technology; in exchange, the integrateds usually receive some preset portion of revenues arising from the sale of oil and gas produced. Such arrangements are dubbed production sharing contracts (PSC).
Integrated oil companies have the advantage of size and experience. These companies have the size and financial resources to spend the billions required to bring a deepwater project online or handle the drilling of complex wells that can take months to drill. They also have the scale to drill exploratory wells offshore or undertake massive seismic shoots to try to pinpoint big new potential reserves in new exploration hot spots such as the deepwater or Artic.
Smaller E&P firms, in contrast, typically target smaller projects and, in many cases, less risky drilling plans. EOG, Quicksilver and XTO, for example, all have land in the Barnett Shale of Texas, a gas reserve that’s well understood and explored. Their production growth comes from simply drilling more wells, more efficiently in this region and optimizing production from those wells.
Despite this important distinction, I look at the same basic fundamental factors when evaluation the E&P business of the integrated oils as I do when examining the smaller, independent E&Ps. The prime factors to consider are production mix between oil and gas, commodity prices, production costs and production growth potential.
A common misconception is that you can simply look at the price of oil and immediately determine how profitable the E&P segments of the major oil companies will be. It’s far more complicated than that.
The easiest way to explain is to look at an example and examine all the moving parts. Let’s take ExxonMobil’s third quarter earnings report. In the third quarter of 2007, Exxon’s upstream (E&P) earnings fell $194 million against the same quarter one year ago. That isn’t a misprint; upstream earnings declined despite near $100 oil.
On the upside, ExxonMobil benefited from higher realizations year-over-year. The term realization refers to the prices the company was able to get for its crude oil and natural gas production.
In this case, the rally in crude oil helped push Exxon’s realization from $65.14 per barrel in the year-ago period to about $71.46 in the third quarter this year. The total effect of realizations was a $630 million benefit to the bottom line.
Of course, $71.46 is a far cry from current oil prices above $90 you hear quoted on the evening news. But that’s not really surprising; the typical crude oil prices you hear quoted are West Texas Intermediate and Brent crudes, some of the most expensive grades of crude in the world. The price of lesser grades—such as heavy or sour crudes—is far below the price of these benchmarks.
If you’re unfamiliar with the concept of different grades of crude, check out the March 21 issue of TES, Looking Refined.
Another positive factor for the upstream business was a category that ExxonMobil calls volume/mix. Volume refers to the total volume of hydrocarbons that the company produces in a year. If we exclude the impact of some extraordinary issues that I’ll detail in a moment, Exxon’s production volume rose about 3 percent in oil equivalent terms.
Offsetting that was a poorer mix of production. This means Exxon produced more natural gas relative to oil this year than it did a year ago. Because global natural gas prices have been flat or declining over the past year, this is negative for the company’s bottom line. Overall, however, Exxon’s volume and mix added a small $20 million benefit compared to last year.
Offsetting the $650 million benefit of realizations, volume and mix were a number of key negatives. The most important of these is that Exxon didn’t see an actual increase in production.
Recall that Exxon reported a 3 percent increase in oil equivalent volumes after accounting for certain extraordinary items; if we don’t exclude those items, production declined 2 percent. Here’s a rundown of those major factors:
PSCs–First, as noted above, many of Exxon’s production agreements with NOCs involve PSCs. Every PSC is a bit different, but most involve some clauses related to commodity prices and cost recovery. The basic effect of these clauses is that, at higher oil and gas prices, the integrated oil firm gets a smaller share of production from the project.
The idea is that NOCs want to allow the integrated oil companies (IOC) to recover their costs. Therefore, up to a certain production level, the IOCs get a higher share of the production. After that cost is recovered, the NOCs step-up their share of the production and profits. In addition, many NOCs negotiate contracts so that they can participate more in commodity price upside.
This is exactly what happened to Exxon. Lower entitlements under PSCs because of high energy costs accounted for about 3.5 percent lower production overall.
Venezuela–Venezuelan President Hugo Chavez has made little secret of his disdain for PSC deals with the big, multinational IOCs. He’s also continued to pursue a plan of re-nationalizing the country’s energy sector.
Part of this trend was the Chavez government’s decision to unilaterally change the agreements governing heavy oil projects in the nation by seizing at least a 60 percent share of these deals. Exxon and ConocoPhillips were unable to reach an agreement with the Venezuelan government in June and exited operations in the nation. Other companies, including Chevron, did renegotiate deals and decided to remain in Venezuela. The decision to exit Venezuela cost Exxon about 1 percent of volumes year-over-year.
The nationalization of energy projects in Venezuela has grabbed the headlines, but the situation there isn’t totally unique. In fact, Venezuela highlights a broader problem of resource access: With commodity prices on the rise, governments the world over are taking steps to renegotiate existing PSC deals or are forcibly trying to grab more control. This is a major ongoing headwind for the industry.
Divestments–The final and smallest piece of Exxon’s volume decline was simply divestments of certain assets. Basically, the company sold various fields around the world; the loss of that production hit volumes. This had about a 0.5 percent impact on volumes.
Exxon’s third quarter earnings release highlights some of the complications involved in evaluating the E&P businesses of the major integrated names. What I tend to look for in evaluating production growth potential is the lineup of projects scheduled over the next few years.
Because IOCs tend to pursue longer-term projects, we have a decent idea of what’s in store over the next few years; although there are often delays, I tend to prefer companies with big projects scheduled for completion near term.
Of course, the E&P business of integrateds does, by its very definition, have significant leverage to commodity prices. As you can clearly see from the Exxon example outlined above, realizations were the most important year-over-year impact to the bottom line.
Although realizations are currently a big positive, inevitable pullbacks in oil and gas prices can quickly turn into a headwind for IOCs. That’s why production growth and new product startups are so important; IOCs can make up somewhat for weak commodity prices by bringing more volume online. Over the long term, E&P companies and integrateds showing the most volume growth tend to outperform.
R&M
Refining is perhaps the most poorly understood area of the energy business. Back in October, several of the big IOCs warmed on their third quarter earnings. I received no fewer than five requests for radio and television interviews to explain how oil could be at $100 and these companies could be reporting weak numbers. The media unfailingly focuses on the E&P business–where $100 oil is a benefit–at the expense of refining.
R&M is that missing link. I’ve explained this phenomenon before at some length, most recently in the March 21 issue of TES.
To summarize, refiners don’t make money by selling crude oil. These firms actually buy crude oil and sell refined products like gasoline and heating oil.
Therefore, refiners make money based on the spread between the cost of oil and that of refined products. If the value of refined products increases faster than the cost of crude oil, refining margins expand and companies make more money in R&M.
But in the third quarter of this year, the opposite happened. The cost of crude oil actually rose faster than the value of refined products; these companies actually saw their refining margins shrink notably. In most cases it was R&M, not E&P, which prompted profit warnings in October.
A very useful quick-and-dirty measure of refining margins 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. This measures the refining profit per barrel of converting three barrels of crude oil into two barrels of gasoline and one barrel of heating oil. Here’s a chart of the 3-2-1 crack spread in the past several months.
Source: Bloomberg
The trend here is clear. After spiking to more than $30 per barrel in May, the crack spread went under $5 per barrel in October. The big run-up in crack spreads in the first and second quarters was due to a series of refinery problems all around the US. These outages meant that refiners struggled to produce enough gasoline to cover the US summer driving season. Meanwhile, US crude oil inventories were usually high because refiners simply weren’t converting that crude to gasoline.
The result: The supply overhang of high crude inventories put a cap on crude prices. Meanwhile shortages of gasoline and refining capacity pushed up gasoline prices. Refining margins truly exploded.
But refining margins subsequently collapsed in late summer after the peak of summer driving season. The primary driver was the rise in crude oil prices; higher crude oil prices depress refining margins for the reasons I noted earlier. Gasoline prices just haven’t risen quickly enough to offset this crude oil rally.
But much of this refining margin effect is seasonal. It’s certainly nothing unique to 2007. The chart below shows the 3-2-1 crack spread on May 1 and the last trading day of October for each year from 2003 to 2007.
Source: Bloomberg
This chart shows that, in every year since 2003, the crack spread has declined between May 1 and Oct. 31. This is mainly the simple consequence of refiners gearing up for the summer driving season during the spring and early summer; they use the third quarter, after the peak of driving season, as a time to perform maintenance on their facilities.
Also note that this seasonal effect is normally quite severe. The smallest seasonal decline in the chart was in 2005. But recall that was the year the a series of hurricanes hit Gulf Coast refining operations; this took a large amount of US refining capacity offline and sent refining margins sky-rocketing during a time of year when margins are typically weak. In every other year, the seasonal effect was pronounced.
I don’t see anything to be concerned about by the fact that third quarter R&M margins fell this year. The decline was dramatic only because margins spiked to unusually high levels in the spring.
Moreover, we’re already seeing a recovery in crack spreads, and I’m looking for margins to improve dramatically in the first half of 2008 as well. See the chart “Crack Spread Positive Seasonality” for a closer look.
Source: Bloomberg
This chart illustrates the crack spread from Jan. 1 to May 1 of each year going back to 2003. As you can see, the seasonal effect in crack spreads is positive in the first five months of each year. That’s because this is when refiners gear up their operations ahead of the summer driving season.
Bottom line: The headwinds in US refining margins that most IOCs reported in the third quarter should reverse into the first and second quarter of 2008.
I also expect a larger-than-normal run-up in margins in the first half of next year. The reason is that US gasoline inventories remain far lower than normal right now; see the chart below.
Source: Bloomberg
As refiners gear up their operations next year for the 2008 summer driving season, they’ll be fighting to bring those gasoline inventories back to more normal levels. That means running refineries full-bore, which raises the odds we’ll see more refining accidents that take capacity offline.
In addition, don’t forget the current situation in the crude oil markets: High crude oil prices are having a negative impact on refining margins right now. I’ve heard a large number of explanations for crude oil nearing $100, but most of those theories are complete bunk. The reality is that crude oil’s rise has very little to do with futures speculation, hedge funds or geopolitical uncertainty and very much to do with the current tight supply/demand balance.
Consider the most recent data for the International Energy Agency (IEA) on crude oil stocks in the Organization for Economic Cooperation and Development (OECD) countries. OECD countries are a good proxy for crude oil stocks in the developed world. Check out the chart below for a closer look at OECD oil inventories.
Source: IEA Oil Market Report
There are a few key points to note about this chart. The first is that I’ve labeled the third quarter of each year as a red bar.
Note that at the end of the third quarter, OECD inventories of crude were considerably lower than a year ago and actually lower than in 2005. Therefore, across the OECD, the supply of crude is tighter than it has been at this time of year since 2004.
Also note the typical change in OECD inventories between the second quarter and third quarter of each year. In a normal year, crude oil stocks actually rise between the end of the second quarter and the end of the third quarter. This corresponds to the end of the summer driving season in the Northern Hemisphere.
Note, however, that there was actually a fall in OECD crude oil inventories in the third quarter this year. Stocks of crude fell approximately 360,000 barrels per day in the fourth quarter, a counter-seasonal crude oil drawdown. That continued into October; early IEA estimates show a further 21-million-barrel draw in the month for OECD countries.
Although US oil inventories remain above average for this time of year, inventories did decline in the third quarter. That’s certainly not the normal seasonal pattern. And we can’t focus solely on the US; oil inventories in Japan, for example, currently stand at their lowest level in at least 20 years.
There are two factors underpinning these inventory draws. First, it appears that the Organization of the Petroleum Exporting Countries (OPEC) isn’t exporting as much oil as it normally would at this time of the year. And second, non-OPEC production growth remains problematic because of faster-than-expected declines in existing field production and a series of project startup delays.
The easiest way to measure the availability of OPEC supply is to look at tanker rates. Check out the chart below for a closer look.
Source: Bloomberg
Recall that tanker charter rates don’t follow the path of crude oil. Tankers don’t make money based on the value of crude oil they ship. In fact, when OPEC is very actively boosting output, that’s great news for tanker rates because it means more product can be carried. Therefore, in periods of strong OPEC supply growth, tanker rates will normally spike as demand exceeds available supply.
This is why you see those prominent “spikes” on the chart of the Baltic Dirty Index of tanker rates above. These spikes tend to occur in the fourth quarter of each year as refiners step up their oil imports to refill inventories.
Although tanker rates have risen somewhat lately, the effect is far less pronounced than it normally would be for this time of the year. This reflects the fact that there are large numbers of idle tankers in the Middle East waiting for shipments. That reflects the fact that there simply isn’t enough oil headed to the US from the Middle East.
Here’s my take on the crude oil market: I’m looking for continued supply tightness into year-end. Over this period, it’s quite possible we could see a spike to more than $100 per barrel, especially if any new non-OPEC projects are delayed. Alternatively, further OPEC rhetoric indicating limited upside to supply, such as we heard over the weekend, could catalyze a spike in crude.
Going into 2008, however, I expect two factors to moderate oil prices. First, I expect OPEC will eventually ship more oil and we’ll see those tanker rates spike somewhat. And second, the IEA offered some tentative signs of demand destruction in its most recent report: Higher oil and refined product prices have started to impact consumers’ demand for crude oil.
The IEA revised 2008 oil demand growth lower by a modest 300,000 barrels per day. Given the obvious weakening in the US economy and the growth scare I outlined at the beginning of this issue, investors are bound to start pricing in a more meaningful decline in demand.
Note I’m not looking for a collapse in oil prices as some bears have been projecting. I’m instead looking for a potential decline to the $70-to-$80-per-barrel range at a maximum.
I always get a kick out of these articles in the major print media that appear every few months, predicting a major decline in oil prices. Remember, most oil bears have been recycling the same arguments about unsustainable geopolitical risk premiums and excess speculation for years.
But the reality is that geopolitical risk is a more or less permanent feature of the global crude oil markets. I just don’t see the US, the EU, Iran and Venezuela deciding to become fast friends overnight.
And I can recall many using the same excess speculation arguments to predict a drop in oil prices below $40 per barrel at the beginning of 2007. The fact is that the unwinding of speculative trades can have an impact on prices in the short run.
In the long run, prices are determined by actual supply and demand. On that front, increased crude oil demand will remain strong in coming years because of strong growth from the emerging markets such as China and India.
Meanwhile, supply growth remains troubled. OPEC’s actual spare capacity—production that can be brought online quickly and sustained—has been falling steadily in recent years. And growth in oil production outside OPEC has consistently undercut expectations.
This is all part of the “End of East Oil” thesis I’ve outlined on numerous occasions in TES. Basically, large onshore fields have become largely depleted and are seeing rapid declines in output. Meanwhile, producers are increasingly targeting more complex reserves such as those in deepwater and the Artic.
Ramping up such complex projects is fraught with difficulty. For example, we’ve all heard about Brazil’s recently discovered Tupi field in the deepwater; this field is among the largest discoveries in recent years.
But what many haven’t heard is just how complex this field is. The Tupi field is located in water 6,000 feet deep and a further 15,000 feet under the seafloor. There’s also a 6,000-foot-deep salt layer to drill through to access this field.
Developing Tupi will involve drilling some of the most complex wells in history. And drilling these wells will require access to advanced deepwater drilling rigs and some complex infrastructure, services and equipment. Given the shortages in the industry, that means at least a five-to-10-year wait for production from this field.
Bottom line: I expect refining margins to expand in the first part of 2008 amid a modest decline in crude oil prices and a seasonal ramp in refining activity. Longer term, I see a continued tight supply/demand balance for crude that will keep prices elevated for years to come.
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How to Play Integrated Oil
The table below highlights seven of the world’s largest integrated oil companies. I’ve purposely excluded NOCs from the list because they’re better treated as a separate group; I’ll cover them in more depth in an upcoming issue.|
Major Integrated Oil Companies
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Company (Exchange: Symbol)
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Forward Price-to-Earnings
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Reserve Replacement (%)
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Price/BOE
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Price/Cash Flow
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% Refining
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| BP (NYSE BP, UK: BP/) | 10.223 | 34.34 | 15.01 | 8.92 | 17.06 |
| Chevron Corp (NYSE: CVX) | 10.123 | 73.67 | 15.96 | 7.68 | 22.83 |
| ConocoPhillips (NYSE: COP) | 8.038 | 308.29 | 11.49 | 5.43 | 30.61 |
| ENI (NYSE: E, Italy: ENI) | 9.374 | N/A | 13.96 | 5.91 | 6.00 |
| ExxonMobil Corp (NYSE: XOM) | 11.944 | 126.16 | 21.96 | 9.50 | 21.66 |
| Marathon Oil (NYSE: MRO) | 8.906 | 108.81 | 31.38 | 8.28 | 42.39 |
| Royal Dutch Shell (NYSE: RDS/A, UK: RDSA) | 10.194 | 129.44 | 22.22 | 7.15 | 31.94 |
| Total (NYSE: TOT, France: FP) | 9.753 | 110.50 | 11.48 | 7.87 | 10.01 |
Source: Bloomberg, company accounts
This table includes what I regard to be some of the most important metrics to watch for IOCs. Most of the table columns are self-explanatory. Two that are less familiar are Price/BOE and Reserve Replacement.
The first is a valuation measure. Essentially, it’s calculated by dividing an integrated’s total market value by the company’s total reserves of oil and natural gas on a barrel of oil equivalent (boe) basis. The higher the number, the more you’re paying for the company’s reserves and the more richly valued the firm is.
The reserve replacement figure simply compares the amount of new oil and gas fields a company discovers or acquires to that firm’s production. Numbers above 100 percent indicate that the company is booking more new reserves that it’s producing; it’s essentially replacing the reserves it produces each year. To make a long story short, the higher this number, the better.
I recommend two of the companies on this list—ExxonMobil Corp and Chevron Corp—both in the income-oriented Proven Reserves Portfolio. However, as of this issue, I recommend selling ExxonMobil Corp for a total profit of close to 60 percent over a roughly two-year holding period; I’ll continue to track it in the How They Rate Table.
When I originally recommended this stock, Exxon had been hit by general weakness in the energy patch and was trading at an attractive valuation. I felt that Exxon was a defensive way to add exposure to a rebound in the energy space.
Although the recommendation has worked out well, my original reasons for buying the stock no longer apply. I don’t think it’s a bad company to own, but I do see several more attractive destinations for your investment dollars.
Note, in particular, that on a Price/BOE, Price-to-Earnings and Price-to-Cash-Flow basis, Exxon is either the most expensive or among the most expensive stocks in the table. Although I can accept some premium because of Exxon’s enormous size and long track record of performance, this degree of valuation premium looks unwarranted.
And Exxon isn’t expected to show much production growth over the next few years. Consensus analyst expectations are for Exxon to show overall production growth of just more than 1 percent annualized through the end of 2010.
Most of that growth is expected to be in the form of higher natural gas production rather than crude oil. In particular, Exxon is looking for considerable growth from its natural gas projects on Qatar. See the map of the Middle East below for a better idea of where Qatar is.
Source: Google
Qatar has the world’s third-largest gas reserves. Better still, Qatar’s fields represent some of the lowest production cost reserves in the world.
The country plans to develop these reserves using a mixture of liquefied natural gas (LNG) and gas-to-liquids (GTL) technologies. (See the April 12, 2006, issue, Finding New Btus, and the Oct. 24 issue, Liquid Gold, for a more-thorough explanation of both technologies.)
According to Exxon, Qatar will be the world’s most important exporter of LNG by 2015. The nation will move from exporting about 25 million tons of gas per year in 2006 to closer to 80 million tons in 2015.
ExxonMobil has stakes in several LNG projects in Qatar; during the next two years, these projects are scheduled to start up and begin shipping LNG. This is behind a good chunk of Exxon’s gas production growth.
Nonetheless, growth in countries such as Qatar will likely just offset natural declines in production from existing fields and existing projects, leaving the company’s total growth roughly flat. Although Exxon’s projects are certainly attractive, world-class opportunities, I’m just don’t view that level of growth as anything exciting. That’s especially true when you consider that the stock is so much more expensive on a valuation basis that its peer group.
Chevron remains my favorite among the US IOCs. In contrast to Exxon, it appears relatively cheap in all three valuation measures quoted in the table–price-to-BOE, price-to-earnings and price-to-cash-flow.
In addition, the company offers a superior dividend yield to Exxon. Although a 2.7 percent yield doesn’t exactly make Chevron an income stock, it’s consistently boosted that payout over time by more than 10 percent annualized over the past five years.
Chevron is also one of the only Super Oils that will show meaningful growth in production over the coming few years. Even more important, it’s scheduled to start up four major projects over just the next two years that will generate significant production growth upside near term. Here’s a quick rundown:
Tahiti–Tahiti is a deepwater field in the Gulf of Mexico where Chevron holds a 58 percent stake. The field is expected to have a peak production rate of 125,000 barrels of oil per day and 70 million cubic feet of natural gas.
Chevron has completed five of the six wells it’s scheduled to drill in this field and has built the pipelines that will carry production to shore. The company also has completed a significant amount of the subsea infrastructure associated with the field.
The Tahiti project was delayed earlier this year because of some problems with parts on the floating production platform that will be used to handle production associated with this field. These giant offshore platforms aren’t simple construction projects, and there are a lot of things that can potentially go wrong logistically.
The delay caused by these construction problems isn’t a huge surprise. Chevron is now on track to begin actual production in the third quarter of 2009.
Blind Faith–Blind Faith is another deepwater development in the Gulf where Chevron has a 75 percent interest. All three development wells originally associated with this project are complete. But the results were positive, so Chevron now has plans to drill a fourth well next year.
With the production platform and subsea infrastructure also nearing completion, Chevron expects Blind Faith production to begin in the second quarter of 2008. Total peak production from the field will be about 45,000 barrels of oil per day and 45 million cubic feet of natural gas.
Agbami–Agbami is a deepwater development offshore Nigeria in western Africa. The floating production storage and offloading (FPSO) platform associated with this field is complete and left the shipyard in Korea to be towed to Nigeria. Management believes the platform will be in place sometime in the first quarter of 2008.
This platform’s completion is a big positive. As Chevron pointed out in its recent conference call, this platform is the largest of its kind in the world. It is capable of processing 250,000 barrels of oil per day and storing more than 2 million barrels.
Chevron has also completed 18 wells associated with Agbami and should begin production by the third quarter of 2008, with production ramping up to full capacity—250,000 barrels per day–within one year. Chevron has a 68 percent interest in the field.
Tengiz–Finally, there’s the Tengiz field located in Kazakhstan. This isn’t a totally new project; it’s simply the expansion of an existing production facility. What Chevron plans to do is to inject sour natural gas—gas with high-sulphur content—back into the Tengiz oil field.
Injecting this gas will help to repressurize the field and increase production from the field. When Tengiz was first tapped, the underground pressure was around 12,000 pounds per square inch (psi), but that’s now down to 8,500 psi in many parts of the field.
This has resulted in high decline rate in terms of actual oil production volumes. Chevron’s project here—where it has a 50 percent interest—would help to reverse that decline rate.
First oil production should begin this quarter and add another 90,000 barrels per day. A second phase of the deal is scheduled for completion in the second half of next year and will add a further 160,000 barrels per day.
As you can see, many of these projects are actually scheduled for startup next year. There’s significant scope for Chevron to generate real oil production growth in 2008.
And it’s worth noting that Chevron reported that the decline rate at its exiting fields has slowed significantly of late. If that trend continues as new projects start up, it could offer even more upside to production volumes.
All told, Chevron’s share of production from these four new projects is more than 400,000 barrels of oil per day worth of production. When you consider that Chevron currently produces about 2.6 million barrels of oil equivalent per day, these projects represent 15 percent of the company’s total production.
In addition to these near-term projects, Chevron has an impressive backlog of projects that are somewhat further from completion. An example of this is the massive Gorgon LNG project in Australia.
This project off the coast of western Australia is the largest ever conducted in that nation. Back in October, the Australian government gave Chevron and the other Gorgon partners the go-ahead. Chevron Corp rates a buy.
I’m also looking seriously at some of the other integrateds on the table. Specifically, Italy’s ENI looks attractive from a valuation standpoint and offers a healthy 5 percent dividend yield.
Eni has a large European natural gas business. Gas demand in Europe is set to soar in coming years. I also like ENI’s portfolio of new oil projects as a source of production growth upside.
I regard this business as highly attractive longer term. I’ll track ENI in the How They Rate Table with the possibility of adding it to the model portfolios in the near future.
ConocoPhillips is also an interesting growth story. In particular, Conoco remains an excellent way to play growth in Russia; the firm has a 20 percent stake in Lukoil. I’ll also track ConocoPhillips in How They Rate Table.
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