The International Energy Agency (IEA) recently announced preliminary findings showing that China has overtaken the US to become the world’s largest energy consumer. If the media attention this story received is any indication, the announcement surprised many. And the news clearly troubled Chinese authorities, who quickly questioned the credibility of the IEA’s data.

Longtime readers shouldn’t have been taken aback by the news; one of the most important and longest-standing themes of this advisory is the growing importance of emerging markets such as China and India to the global energy puzzle. Chinese authorities were quick to downplay this news because the country has come under fire, primarily in the West, for using too much energy and producing too much pollution.

The West’s cavils appear increasingly hypocritical. After all, the US and all other developed countries built their economic might on energy produced primarily from fossil fuels. Pundits forget that US and Western European energy consumption rose exponentially alongside disposable income in the early 20th century. A similar phenomenon occurred in Japan and South Korea during the latter half of the century. It’s only natural that consumers in today’s emerging markets would wish to reap the same benefits.

The IEA data refers to primary energy consumption–energy derived from coal, oil, natural gas, nuclear and all other energy sources–so it doesn’t mean that China is even close to overtaking the US in oil consumption. The agency may also revise the data–this is just a preliminary figure.

However, the trends are and implications are clear: Investors can ill-afford to make forecasts about global energy prices by simply looking at the latest weekly inventory data from the US. Nor can speculators be blamed for soaring energy costs; emerging markets continue to drive an increase in global demand. Big integrated oil companies are one way to play an increasingly international energy market.

In This Issue

The Stories

Big integrated oil companies are traditionally considered the most defensive plays in the energy sector, but the TES Integrated Oil Index has underperformed of late; the group offers attractive valuations for long-term investors. See Big Oil, Big Value.

Growing oil production remains a challenge for the biggest integrated oil firms, but natural gas offers long-term opportunities. See Upstream Growth.

Refining operations continue to weigh on earnings, but it’s not all doom and gloom. See Downstream Improvements.

What fundamentals should investors consider when evaluating integrated oil companies? Learn about these key factors and how the Super Oils stack up in Drilling Down.

Elliott runs explains the rationale behind his top three Big Oil picks. See Super Picks.

The Stocks

Valero Energy Corp (NYSE: VLO)–Buy @ 20, Stop @ 14.95
ExxonMobil Corp (NYSE: XOM)–Buy @ 65
Chevron (NYSE: CVX)–Buy @ 85
Eni (Italy: ENI, NYSE: E)–Buy @ 52

Big Oil, Big Value

Big integrated oil companies are traditionally considered the most defensive plays in the energy sector. Companies like Portfolio recommendation ExxonMobil Corp (NYSE: XOM) are less volatile than the S&P 500, offer above-average dividend yields and have a history of performing well even amid weak commodity prices.

Consider that Exxon Mobil’s beta based on 20 years of weekly returns is 0.78. Beta is a measure of a stock’s volatility relative to the S&P 500. A beta greater than 1.0 indicates that the stock tends to move faster than the index; a beta between zero and 1.0 indicates that the stock is less volatile than the index as a whole; and a beta less than zero suggests the stock tends to move in the opposite direction to the S&P.

Exxon has generated a total return of just under 700 percent–11 percent annualized–over the past two decades, compared to just 340 percent for the S&P 500. Even more impressive, Exxon generated gains of 363 percent in the 1990s, nearly matching the S&P 500’s 423 percent return despite weak energy prices through much of the decade.

Although ExxonMobil and its ilk deserve their long-term reputation for safety and consistent profitability, the group’s short-term picture isn’t as rosy. One would expect the integrated oils to perform better when the tape is weak, but the TES Integrated Oils Index has declined 15.6 percent in 2010. (Click here more information on the nine proprietary TES Indexes.)

Predictably, shares of BP (NYSE: BP), a stock that the markets have ravaged since the disaster in the Gulf of Mexico, account for a good deal of this underperformance. That being said, even omitting BP, the TES Integrated Oils Index has still lagged the S&P 500 Energy Index this year.

That’s a surprise when you consider that the big oils tend to perform well in weak markets and underperform when energy stocks soar. ExxonMobil, the quintessential energy blue chip, is off 12.6 percent so far this year.

This unusual situation presents a compelling opportunity for investors, as Big Oil has been beaten down due primarily to psychological and technical factors. In particular, institutional investors have pared exposure to the energy sector in response to the BP oil spill, throwing away the proverbial babies with the bathwater. Most of the big integrated oils I cover trade at their cheapest valuations since the panic-induced lows in late 2008, but their underlying fundamentals remain intact.

Exploration and production (E&P) operations continue to benefit from elevated crude oil prices. Meanwhile, the refining and marketing business has weighed on results over the past two years but appears to be turning around. Ultimately, the group may benefit from new regulations on drilling in the deepwater Gulf of Mexico; only the largest integrated oils will have the scope to handle such developments and meet stringent requirements.

Big Oils are a classic value investment proposition at current prices; now is the time to go shopping.

Upstream Growth

Investors often regard Big Oils as mysterious profit-generators because of all their moving parts, but they’re fairly simple companies.

Most of the integrated oil companies amount to a combination of upstream and downstream operations. Upstream activities include the exploration for and production of crude oil and natural gas; downstream operations focus on refining and marketing.

Broadly speaking, integrated oils generate roughly three-quarters of their profits from upstream operations and the remaining 25 percent from downstream business lines. Of course, this ratio varies widely on an individual basis, but it’s a useful ratio to keep in mind when evaluating the group.

I’ve written about pure-play E&P companies on numerous occasions, so I won’t spill too much ink on upstream operations. Suffice it to say that the basic fundamentals to keep in mind are the path of oil and natural-gas prices and the potential for production growth. Clearly, integrated oil companies make more money producing and selling oil when the prices of these commodities are
high and rising.

And over the long term, companies that can generate real growth in oil and gas production volumes tend to outperform.

What differentiates the big integrated oils from smaller independent E&P firms is the scope of their projects; the big oils tend to pursue larger, longer-term development projects. These endeavors often involve large, up-front capital commitments, but some of these completed plays have relatively cheap production costs; Big Oils generally remain profitable at lower commodity prices.

Commodity prices are the key driver of upstream operations. Generally speaking, the commodity price environment is favorable to the integrated oils right now. Although the revenue mix varies significantly among the majors, most are heavily weighted toward oil production.

And many of the majors with exposure to natural gas are involved in international gas markets and, in particular, liquefied natural gas (LNG) projects. Many of these endeavors are at least partly supported by long-term supply contracts that are profitable even at relatively low natural gas prices.

On the crude oil front, I monitor the average prices of the two most important benchmarks: Brent and West Texas Intermediate (WTI) oil. Here’s a look at average crude prices in the second quarter of 2010 as compared to prior time periods.


Source: Bloomberg

Average oil prices in the second quarter were almost identical to the first quarter of 2010. Prices for Brent crude, a key international benchmark, increased a bit in the second quarter, while US WTI was less than $1 per barrel lower, on average. The year-over-year comparison with the second quarter of 2009 is easy; no matter which benchmark you examine, prices are nearly $20 a barrel higher than a year ago. And while there’s less than a month’s worth of trading data to examine, average crude prices are fairly stable in the early days of the third quarter.

When the major integrated oils report second-quarter results over the next few weeks, upstream operations should be solid because of higher realizations. In other words, companies are receiving much higher prices for their production than a year ago.

At present, North American natural gas prices are languishing because of strong supply growth from US unconventional gas reserves (shale plays) and weak demand resulting from the lingering effects of the recession. These two factors have led to a glut of gas in storage in the US, keeping a lid on prices.

I’ve written extensively about gas over the past year and will have more to say in an upcoming issue. For now, suffice it to say that in the near term North American gas demand continues to recover from the 2008-09 recession, though consumption still lags behind robust supply growth from prolific and cheap-to-produce US unconventional plays.

However, the long-term prospects for demand growth are outstanding because of the region’s abundant supply of natural gas and concerns about energy security.

Don’t allow short-term supply conditions in North America to color your analysis of the Big Oils. The US has one LNG export facility in Alaska and obtaining the permits to construct a gas liquefaction facility in the Lower 48 would be tough. Although the country has plenty of LNG import (re-gasification) terminals, converting these to liquefaction facilities isn’t an option.

For at least the next few years, most North American gas won’t leave the continent. That being said, the long-term outlook for gas demand in Asia is stellar.


Source: BP Statistical Review of World Energy 2010

As I mentioned in the introduction to today’s issue, China is now the world’s biggest energy consumer. China’s growing appetite for energy commodities is also shaking up the equation in Asia; the Middle Kingdom surpassed Japan as the continent’s leading consumer of natural gas.

At 8.6 billion cubic feet per day, Chinese gas demand is still a fraction of US consumption but has more than tripled since 2000. India’s gas consumption has doubled over the same period and jumped an astounding 25 percent in 2009 despite the lingering impact of a global recession. India’s gas demand is growing faster than Chinese consumption–not an easy comparison.

Although weak natural gas prices in North America may be a short-term negative for big oils with exposure to the US and Canadian markets, don’t misconstrue this to mean that all exposure to gas is bad. Asian nations are locking up supplies of LNG from key Australia and other key regional producers in anticipation of higher future demand.

Meanwhile, looking past short-term supply and demand imbalances, I remain bullish on global gas demand: Natural gas is cheaper, cleaner and more abundant that oil–advantages that should boost gas’ profile in the global energy mix.

Investors interested in the Big Oils should examine the potential for production growth on a company by company basis. Generally speaking, most of the big integrated oils have struggled to boost their overall energy output in recent years–a trend that should continue, especially with respect to oil production.

The main problem is that every year, a major oil company needs to develop new projects just to maintain their output. Production from existing, mature fields naturally declines each year as the reservoir depletes and underground pressures abate. Most of the data suggests that decline rates from mature fields are generally accelerating, exacerbating the problem.

New projects must first offset natural decline rates–a bigger challenge as time progresses. In other words, producers are running on a treadmill, and the speed of that treadmill is accelerating.

To worsen matters, some of the best and most prolific reserves are off-limits to the Big Oils; many of the largest unexploited fields are located in international markets and are controlled by state-run, or partially state-run, national oil companies (NOC). In these areas, the integrated oils are forced to partner with NOCs on attractive fields; over the past decade rising commodity prices emboldened the NOCs to demand more attractive deals.

And don’t forget that most of the integrated oils are big companies, among the largest in the world based on market capitalization. Small projects don’t move the proverbial needle for these companies. For this reason, it’s easier for smaller names such as Gushers recommendation Afren (London: AFR) to grow production.

This scenario isn’t a total nightmare for the integrated oils; they can still squeeze plenty of profit from their fields, even as output wanes. However, production growth is at a premium; shares of integrated oil companies that have the scope to grow their output should command a higher valuation.

Downstream Improvements

The downstream business been paddling upstream. In the fourth quarter 2009 and first quarter 2010, several of the Big Oils discussed efforts to rationalize and cut costs in their refining businesses to improve profitability.

Refining is one of the most important and cyclical energy-related industries–it’s also widely misunderstood.

I offered a detailed analysis of the fundamentals driving profitability in refining and my outlook for the group in the Feb. 17, 2010, issue A New Dark Age for Refiners. My conclusion: Refining margins won’t return to the heightened levels of a few years ago anytime soon, but the stocks were too cheap, and the group’s profitability would likely improve a bit. In addition, North American refining margins usually improve into mid-summer as refiners gear up for summer driving season.

In this issue we’ll take a closer look at the latest trends for refiners. To gauge refining margins, most analysts watch the NYMEX 3-2-1 crack spread, which measures the profitability of turning three barrels of crude into two barrels of gasoline and one barrel of heating oil (diesel).

As I forecast in the Feb. 17 issue, the NYMEX 3-2-1 Crack Spread trended higher from the $7 to $8 per barrel to above $15 a barrel in mid-May. Spreads topped out in June–a normal seasonal pattern–and have pulled back to around $9.25 per barrel as of July 20.

Some analysts argued that a combination of weak US gasoline demand and excess refining capacity would depress the normal seasonal refining cycle this year. This scenario hasn’t played out. In fact, US oil demand has increased 5 to 8 percent year over year, and refining margins have improved from their winter lows.

The average 3-2-1 crack spread in the first quarter was about $9 a barrel, compared to about $12.30 a barrel in the second quarter. As the Big Oils report second-quarter earnings, their refining businesses should show solid sequential improvement. And in the second quarter of 2009, the 3-2-1 Crack spread averaged $9.91, so the year-over-year comparables are supportive.

The most important point to keep in mind is that expectations for downstream profitability are already low; the market will welcome any improvement in the refining business.

And as I noted in the Feb. 17 issue, there’s more to refining profitability than just the 3-2-1 crack spread. Two additional factors to watch are an integrated oil company’s regional exposure and crude oil mix.

Regional exposure is important because, as every consumer knows, gasoline and diesel prices vary widely in different parts of the US.

For example, on the East Coast, US-refined gasoline may compete with products imported from Europe. European refiners may export gasoline if margins are more attractive in the US. Also, the cost of sourcing crude can vary widely in different parts of the country, depending on factors such as which pipelines serve a particular region. Demand also varies regionally.

As of the close on July 20, crack spreads on the West Coast were as high as $16.50 a barrel, compared with $7 to $8 a barrel in parts of the Gulf and East Coasts. This West Coast advantage has been consistent for most of 2010.


Source: Bloomberg

The blue line represents the 3-2-1 Crack spread obtained by refining Alaskan crude into gasoline and heating oil (diesel) for delivery to Los Angeles. The red line represents the approximate margin obtained by refining WTI crude into gasoline and heating oil for delivery to New York Harbor.

Keep in mind that these margins are approximations based on publicly available data about the prices for various refined products and grades of oil. Despite these shortcomings, the graph tells a lot about regional profitability–at least directionally.

As you can see, West Coast refining margins haven’t followed East Coast margins lower in recent weeks. Integrated oil companies with exposure to the West Coast or those with diversified geographic exposure are likely to be more profitable than those with a heavy concentration on the US East Coast.

Last but not least, it’s a good idea to keep an eye on the price differentials between various grades of crude oil. I explained the importance of this in the Feb. 17 issue, but here’s a quick summary.

Many different types of crude oil are available. “Light, sweet” crude such as WTI and Brent command a higher price because they’re low in sulfur and easy to refine. Conversely, heavier and sourer grades of crude tend to trade at a discount.

This differentiation affords refiners a degree of flexibility when oil prices increase. Faced with higher input costs, refiners often buy cheaper grades of crude to boost profit margins. But not every refiner has the equipment to process heavy, sour crude.

Here’s a graph depicting the price differential between two different grades of crude oil, WTI and Maya.


Source: Bloomberg

The NYMEX crude oil contract is based on WTI crude, which has a standard American Petroleum Institute (API) gravity of 39 degrees and a sulfur content of 0.34 percent. Oil with API gravity higher than 31 degrees is considered light, and crude with less than 0.5 percent sulfur is dubbed sweet. Accordingly, WTI is light, sweet crude oil.

Maya is a Mexican oil benchmark that’s based on the quality of oil that comes from Mexico’s largest field, Cantarell. Maya crude has an API gravity of 22 and a sulfur content of 3.3 percent–it’s heavy, sour crude oil.

To calculate the data depicted in this graph, I subtracted the price of Maya crude from the price of WTI. For example, as of last Friday’s close, the WTI-Maya differential is $9.07 per barrel.

Although the Maya-WTI spread is still well off its 2008 highs, it’s been in a steady uptrend since the beginning of 2009. The differential in the second quarter of 2010 was a good deal higher than 12 months earlier, providing for solid year-over-year comparisons.

Proven Reserves recommendation Chevron (NYSE: CVX) recently offered a detailed update on its downstream business. In a July 12, 2010, press release, the company noted that its refining operations would benefit from many of the trends I outlined, a good sign that the refining segment could come in above expectations when Chevron reports its earnings on July 30.

Two additional points are worth mentioning. First, note that the TES Refining Index is roughly flat for the year–not particularly impressive, but it does mean that refiners have handily outperformed the broader market averages this year. This is a sign that the group is sold out; current valuations price in the bad news and limit downside risk.

Pure-play refiner Valero Energy Corp (NYSE: VLO) is a short-term trade in the Gushers Portfolio. I updated my outlook for refining margins in this issue to frame an analysis of the integrated oils–in particular the Super Oils–but the same basic downstream fundamentals also apply to Valero. Shares of Valero currently trade at less than 0.13 times sales and 7.8 times next year’s earnings estimates–in both cases, well below its average valuations over the past 10 years.

The stock could hit $30 if US oil demand growth continues to pick up through year-end, driving increasing confidence in refining margins. Buy Valero Energy Corp under 20, with a stop at 14.95.

Drilling Down

Integrated oil firms are a combination of upstream and downstream businesses. As I just explained, the outlook for upstream operations remains solid, while the bar of expectations for refining remains low despite signs of improving fundamentals. Shares of many Big Oils trade at below-average valuations and represent a great buying opportunity.

Which integrated oil names offer the best upside?  Let’s look at the numbers for seven of the world’s largest Big Oil companies. Note that this series of three tables doesn’t include NOCs, refiners or smaller E&P firms.


Source: Bloomberg

Most of the columns in this table are self-explanatory, but here’s a review of some terms that may be less familiar.

Enterprise Value – Enterprise value measures a company’s size, taking into account both the value of the shares and net debt (debt minus cash) into account. With an enterprise value of $100 billion, Proven Reserves recommendation Eni (Italy: ENI, NYSE: E) is the smallest name in the table; ExxonMobile boasts an enterprise value near $270 billion, tops on the chart.

Indicated Yield – This is the stock’s dividend yield, which is calculated by dividing the annual dividend by the current share price. The European entries in our table offer higher yields than their US counterparts; Eni, Total (NYSE: TOT) and Royal Dutch Shell (NYSE: RDS.A) each yield over 6 percent. BP discontinued its payout in the face of political pressure and massive
clean-up costs.

Price to Earnings (P/E) – The table lists the P/E ratio based on estimates for 2010 earnings, a more relevant number than the oft-quoted trailing P/E because it’s forward-looking.

Price to Cash Flow – This is a good basic measure of valuation for the integrated oils. Strong cash-flow generation is the group’s hallmark. Note that ExxonMobil is the most expensive name based on this metric; the stock usually trades at a premium thanks to a long history of solid execution and an enormous production portfolio. BP is the cheapest because of the disaster in the Gulf of Mexico.

% Oil – This column is based on 2009 production in millions of barrels of oil equivalent per day. To calculate total production in oil-equivalent terms, natural gas production is equated to oil production on an energy equivalent basis. This column indicates the extent to which a company’s oil output contributes its overall oil-equivalent production. The higher this percentage, the more exposure the integrated producer has to oil prices.

As I noted earlier, the long-term outlook for natural gas prices and demand is solid. However, in the near term, a higher oil exposure provides a slight tailwind because oil prices remain solid. Chevron has most exposure to oil; Royal Dutch Shell and ConocoPhillips (NYSE: COP) have the least.

Note that although ExxonMobil has traditionally been an oil-heavy producer, in 2010 the firm will have more exposure to natural gas thanks to its acquisition of XTO Energy.

The second table covers the same seven stocks and breaks down each firm’s outlook for reserves.


Source: Bloomberg

This table is a bit more complex; here’s an explanation of each column and my comments on each metric.

Reserve Add 2009 – This is the total reserves each company added in 2009 and is quoted in millions. For example, Exxon added about 1.87 billion barrels to its reserve base last year. Evidence of reserve growth is a positive.

% Produced – To calculate this figure, I divided each company’s oil-equivalent production in 2009 by each company’s reserves at the beginning of that year. For example, ExxonMobil produced about 7 percent of its total reserve base in 2009. A lower figure is preferable because it indicates that the company has longer-lived reserves. As you can see, ExxonMobil leads the pack on this metric.

% Revision – Many investors assume that when a company books new reserves, the firm located new fields full of oil or gas. But that’s not the only way a producer can book reserves. Reserves are estimates based on the size of a field and the total assumed recovery factor, the percentage of the oil in the field that’s ultimately likely to be produced. There’s no way to measure precisely how much recoverable oil is in the ground.

This column shows what percentage of a company’s total 2009 reserve additions came from revisions. It’s worth distinguishing new reserves booked through actual exploration rather than “on paper” revisions. As a rule of thumb, the market regards revisions as a lower-quality form of reserve addition and prefers new reserves booked through actual drilling.

% E&E – This column stands for Exploration and Extensions, the percent of 2009 reserve additions booked due to the discovery of new fields or extensions to existing fields. To extend a field, an operator would drill new wells near existing wells to attempt to delineate the boundaries of a certain oil- or gas-bearing reservoir. A higher percentage of additions through E&E is preferable.

% Acquired – Companies also increase their reserve bases by acquiring fields and properties from other producers. Most of the Big Oils rationalize their portfolios every year, divesting non-core assets and buying other assets. When a company sells more reserves than it buys, this column would be a negative percentage.

Our final table evaluates costs for all seven of the integrated oils.

Source: Bloomberg

This table examines operating revenues for each firm and various operating costs. For example, the column labeled “Production Cost/Revenues” shows total oil and gas production costs as a
percentage of operating revenue. Lower cost percentages are ideal.

Quantitative data offers a useful starting point, but it’s always important to scrutinize firms from a qualitative point of view as well. Investors should look for integrate oil firms with two qualities: A history of generating solid cash flows from projects and an attractive slate of new upstream projects that can boost reserves and production. Here’s an in-depth look at three of my favorites.

Super Picks

ExxonMobil is the largest of the integrated oils based on market capitalization, enterprise value and daily production in oil-equivalent terms. The company also has a well-deserved reputation for quality and stability; ExxonMobil has no net debt as well as a coveted, and increasingly rare, “AAA” credit rating from Standard & Poor’s.

ExxonMobil is also noted for its commitment to profitability and long-term value. Case in point: Its 2009 return on assets was 8.4 percent, and its return on equity was 17.3 percent–tied for the lead among the Super Oils.

In recent years the behemoth has struggled to grow its production base, largely because the firm produces the equivalent of nearly 4 million barrels of oil per day; given this massive output, even a modest decline rate requires a large number of new projects to hold production steady. In fact, Exxon’s liquids production–oil and natural gas liquids (NGL)–has decreased every year since 2006, while its natural gas output in 2009 was roughly equal to the previous year.

Expect the company to post relatively flat production growth over the next few years as well. ExxonMobil has a number of projects coming on-stream between 2010 and 2012, though decline rates on existing fields will offset much of that growth.

To emphasize the sheer size of the company’s operations, here’s a list of projects that were recently finished or are slated for completion.

Qatargas 2, Trains 4 and 5: This integrated LNG operation is a joint venture with Qatar Petroleum that entered production in 2009. ExxonMobil owns a 30 percent stake in Train 4 and an 18 percent stake in Train 5.

Qatar’s North Field, which extends into Iran, is widely considered the world’s largest non-associated natural gas field, meaning that it’s the largest gas field where the gas is not found dissolved in crude oil. Ultra-low production costs make the field profitable even when natural gas prices are depressed.

LNG–super-cooled gas in liquid form–frees North Field production from the constraints of a limited pipeline network and allows the gas to be shipped worldwide via tanker.

Most of the production from the Qatar projects is destined for the UK, a country becoming more reliant on imported gas because of declining output from the North Sea and a desire to reduce its dependence on Russian supplies.

RasGas Train 6 – ExxonMobil holds a 30 percent stake in the joint venture with Qatar Petroleum. The project was completed 2009 and yielded its first LNG in 2010.

Piceance Phase 1 – ExxonMobil owns 100 percent of this natural gas project, which went into production last year and averaged around 108 million cubic feet of gas per day. As the project progresses, management expects output to reach 200 million cubic feet per day in 2012.

Sakhalin-1 Odoptu – This is an oil project located in Sakhalin Island in eastern Russia. ExxonMobil owns 30 percent of the project and expects output to peak at about 35,000 barrels per day.

Angola – ExxonMobil has interests a series of Angolan fields slated to enter production between 2011 and 2012. The list includes the Pazflor development in which ExxonMobil owns a 20 percent stake; estimates peg peak production at 200,000 barrels per day. The 25 percent-owned Plutao-Saturno project will generate 150,000 barrels per day at its peak.

Australia – ExxonMobil holds a 40 percent interest in the Kipper/Tuna development, a project expected to generate 15,000 barrels per day of oil production as well as some gas. The Turrum field, in which the firm has a 50 percent stake, should produce 200,000 barrels of oil per day and 200 million cubic feet of gas per day.
 
Canada – ExxonMobil’s Kearl Phase 1 oil-sands project is designed to produce 140,000 barrels of oil per day.

Though by no means exhaustive, this list of projects provides a glimpse of the sheer depth and breadth of ExxonMobil’s upstream portfolio. These efforts may not be enough to grow the company’s production, but output should remain stable–and with the addition of XTO Energy, the firm’s exposure to shale-gas plays should enable it to expand gas production.

ExxonMobil’s downstream operations generate nowhere near as much profit. Although the exact ratio varies from year to year because of the industry’s cyclicality, ExxonMobil typically garners an average of 20 to 25 percent of net income from its refining and chemicals production businesses.

Profitability in downstream operations is driven by prevailing margins; despite its position as the world’s biggest refiner, ExxonMobil’s refining business is still subject to cyclicality. The company evaluates the profitability of the business over the full cycle, averaging the lean years with the boom years. Boasting huge financial resources, the energy giant can invest in its facilities in weak markets and afford to bide its time before the next boom. Not surprisingly, ExxonMobil’s refineries are among the world’s most efficient–and most profitable.

ExxonMobil also wins points for diversification. Not only is the Super Oil well-diversified regionally in the US and able to handle a wide array of different crude types, but the firm also has significant capacity in Asia and other fast-growing markets.

In light of its attractive asset base and operating excellence, the obvious question is why Exxon has underperformed peers in recent months. The main reason for this weakness represents a source of future strength: The oil giant’s acquisition of US-focused natural gas producer XTO Energy.

XTO Energy was a Wildcatters Portfolio recommendation when ExxonMobil announced the deal in late 2009. Under the terms of the transaction, XTO’s shareholders received 0.7098 shares of ExxonMobil for each XTO share held. The Super Oil also took on about 10.4 billion in net debt owed by XTO.

At the time of the announcement in December the full value was $41.37 billion, though the decline in ExxonMobil’s share price between the announcement and consummation date lowered the full value to $34.9 billion–a large acquisition deal by any measure.

Investors appear concerned that ExxonMobil might have paid too much for XTO, while some have expressed concerns that the new assets increase the profile of natural gas in Super Oil’s production mix.

The market has vastly overreacted to both concerns, furnishing savvy investors with an excellent opportunity to buy ExxonMobil’s shares.

And there’s plenty to like about XTO Energy’s business model. The acquired firm is a US-focused natural gas producer with a long history of operating in the Barnett and Haynesville Shale, among other unconventional natural gas plays.

Moreover, XTO and ExxonMobil share similar strategies; both firms built a reputation for driving down costs in new fields through efficiency gains.

XTO also brings a lot of know-how to the table, a valuable asset as ExxonMobil seeks to exploit the significant unconventional acreage its amassed both in the US and internationally. At present, shale-gas production is primarily a North American phenomenon, though ExxonMobil and other producers are eyeing similar deposits overseas.

Granted, the deal increases the ExxonMobil’s exposure to natural gas, but as my rundown of upstream projects suggests, the company was already headed in that direction before the tie-up with XTO. This strategic shift reflects the company’s long-term outlook for energy markets; management expects demand for natural gas to accelerate at a much faster rate than the market for any other energy commodity between now and 2030.

As I noted in the introduction, this view isn’t that far-fetched when you consider the impressive demand growth in China and India. The market is paying too much attention to the near-term outlook for gas in North America; I expect gas prices to return to $6 per million British thermal units over the next one to two years.

In addition, I don’t agree that Exxon overpaid. Although Exxon issued new shares for XTO holders, the deal doesn’t represent much of a financial burden for a company of Exxon’s size.

And with gas prices depressed in late 2009 and sentiment weak, ExxonMobil wasn’t exactly buying into the industry at the height of euphoria–the deal is a value play on a business that will be of increasing strategic performance down the line.

This shortsightedness affords investors an opportunity to pick up a long-term value creator at a cheap price. Readers who received shares of ExxonMobil as part of the XTO transaction should hold onto the stock. Yielding 3 percent, ExxonMobil is a buy up to 65 in the Proven Reserves Portfolio.

Proven Reserves recommendation Chevron is the only Big Oil name that’s likely to grow production significantly in coming years thanks to a long list of projects underway. And Chevron is the “oiliest” of the group, generating nearly 70 percent of its production from oil.

Another big plus: Much of Chevron’s reserve additions have come through the drill bit rather than the pen tip, a testament to the quality of the firm’s global exploration program.

In 2009 the company’s existing production base declined by 130,000 barrels per day, but a series of major international projects offset these losses and expanded production by 305,000 barrels per day.

Here’s a look at some of Chevron’s major projects that recently entered production or will begin producing in a few years.

Agbami – This project offshore Nigeria began producing in 2009 and achieved peak production of 250,000 barrels per year by August.

Tengiz – Chevron is developing this field with Kazakhstan’s national oil company. Production from the play has ramped up to 250,000 barrels per day, and Chevron is making efforts to boost production further.

Blind Faith – A huge offshore platform moored in the deepwater Gulf of Mexico, Blind Faith collects production from wells located in about 7,000 feet of water. The development saw peak production of about 70,000 barrels per year in March 2009.

Because Blind Faith has gathered oil from existing wells for more than a year, Obama administration’s drilling moratorium won’t affect it; companies are permitted to do basic maintenance on wells when needed.

Tahiti – Tahiti is another deepwater development located in the Gulf of Mexico. At more than five miles in total depth, it has the distinction of being the deepest producing well in the Gulf.

Tahiti produced 135,000 barrels of oil equivalent per day in July 2009, 125,000 barrels of oil and 70 million cubic feet of natural gas. Again, as a producing field, Tahiti shouldn’t be impacted by the Gulf moratorium.

Tombua-Landana – Located in 1,200 feet of water off the coast of Angola, Tombua-Landana is another big deepwater field. The play achieved first oil in 2009, and Chevron expects a peak production rate of 100,000 barrels of oil per day in 2011.

Frade – Chevron has a 51.74 percent stake in this deepwater project located in 3,700 feet of water 230 miles offshore Brazil. Production commenced in 2009 and is expected to peak in 2011 at around 72,000 barrels per day.

Looking a bit further into the future, Chevron has several new projects slated to enter production over the next few years. The list includes expansions to the Agbami field and Tengiz project as well as a series of large-scale LNG projects in Australia that should benefit from growing Asian demand for the commodity.

Chevron also has a long list of deepwater projects offshore Africa and Brazil and in the Gulf of Mexico. Although some of the Gulf plays may be delayed by the moratorium, they do offer longer-term upside, and Chevron has the financial power to handle any new safety regulations.

All told, Chevron expects to boost its production at an annualized rate of 1 percent through the end of 2014. After 2014, management forecasts production growth of 4 to 5 percent per year as a number of major projects come online.

Chevron’s downstream business has been a drag for some time. However, management has indicated company that margins are improving. Over the long term, layoffs and other cost-cutting measures should boost profitability. And Chevron’s significant refining footprint in California is a major positive given the superior margins in that market.

Despite its superior growth prospects, Chevron is among the cheapest Big Oils in the table. Buy Chevron up to 85.

Italy’s Eni is smallest name in the table, but the stock offers the highest yield (6.6 percent) and trades at a considerable discount.

Whereas ExxonMobil is a blue-chip value play and Chevron is a production growth story, Eni is an aggressive, out-of-consensus turnaround story.

Unlike the other integrated oils I cover, Eni is a combination of three basic businesses: upstream exploration and production, downstream refining and a gas and power utility division.

The latter division imports gas into the EU and resells gas to customers in its native Italy and other European countries. This segment also owns power plants around Italy and operates like a traditional utility. The gas and power business suffered in 2009 because of weak demand for natural gas and power across the EU and in Italy–a product of the languishing economy.

According to Eni’s projections, EU gas demand fell 7.4 percent in 2009 from 2008 levels. For Italy, demand is off more than 12 percent from pre-crisis levels.

I’ve written extensively about the market’s ongoing concerns about fiscal austerity in Europe and sovereign credit issues on the Continent. These macroeconomic fears raise concerns about the potential for continues weakness in Eni’s gas and power division. Since the division accounted for about 30 percent of net income last year, it remains a concern.

I expect gas and power sales to be weak in 2010 and 2011, but this is a well-known issue that’s already reflected in Eni’s valuation and Wall Street’s general negativity toward the stock. I expect slow growth in Europe but no outright recession. Over the long term, Europe’s efforts to cut carbon emissions bode well for natural gas demand, as the commodity is the cleanest fossil fuel.

The firm’s downstream operations lost money in 2009, hit by weak refining margins. But improving profitability in this segment should make it less of a drag this year.

Eni’s upstream operations are its crown jewel and could provide upside to the consensus view. Production was flat in 2009 after production cuts implemented by OPEC are factored out. As oil demand recovers, OPEC should raise its quotas, eliminating this issue. And the situation has already improved because many OPEC members are producing more than their quota to take advantage of rising oil prices.

In addition, Eni hosted a seminar on June 7 to discuss the company’s upstream opportunities, firming up expectations. Management reiterated guidance for slightly higher production this year and highlighted a solid growth outlook of around 2.5 percent annualized through 2013.

Eni has always had a strong position in Africa, a natural expansion opportunity for an Italian firm. Not surprisingly, the company sees plenty of opportunities in Africa going forward. Eni highlighted some successes boosting production and recovery factors from key oilfields and gas plays in North Africa. Eni is the top producer in Egypt, Libya, Tunisia and Algeria.

Over the long haul, Eni has some expansion and exploration opportunities in West Africa, one of the hottest offshore production markets. The list includes onshore and offshore plays in Ghana, Gabon and Mozambique. Eni is already a significant producer in Nigeria, Angola and the Congo and is targeting 9 percent annualized growth from the region through 2013. Outside its core African markets, Eni has potential in Venezuela, the Arctic Barents Sea and Western Australia.

One of the single largest projects on Eni’s plate is the development of Iraq Zubair field, a play whose output has suffered from political factors for decades. Nevertheless, production is at 180,000 barrels per day, and Eni estimates that it can hit the target rate of 700,000 barrels per day by 2013 and reach 1.2 million per day by 2020. Although these estimates strike me as high, there’s no question that Eni has significant upside from current production levels.

Another concern that’s weighed on Eni over the past two years is that it has more debt than most of the Big Oils and has been lower its dividend on a couple of occasions since 2008. Another cut appears unlikely unless oil prices fall below USD60 a barrel and remain at depressed levels for some time.

The local shares pay a total of EUR1 each year. But the NYSE-traded American depositary receipt (ADR) represent ownership of two local shares. Therefore, the dividend to ADR holders should be around 1 euro twice per year.

The actual dollar amount you receive by owning the ADRs depends entirely on the dollar-euro exchange rate. Eni continues to rate a buy under 52.