Total (Paris: FP, NYSE: TOT)

On March 25, France-based Total announced that it had detected a natural gas leak at its Elgin Platform in the UK portion of the North Sea, about 240 kilometers (150 miles) from the Scottish coast near Aberdeen. The company shut in the wells surrounding the platform and evacuated all personnel safely with no reported injuries. Total also set up a 2-mile safety perimeter around the field to protect passing boat traffic from danger.

Total’s stock pulled back substantially the following day, as investors speculated about how much revenue the company would lose by shutting in the well and about the costs from related fines and remediating environmental damage associated with the leak.

After the Macondo oil spill in spring 2010, disasters of this nature put the investment community on edge, particularly when they occur in the West. Recall that in the wake of the blowout in the Gulf of Mexico, pundits speculated that the damages associated with the spill would bankrupt BP (LSE: BP, NYSE: BP).

Although the recent natural gas leak in the North Sea inevitably led to hasty comparisons to what transpired in the Gulf of Mexico, the two disasters bear scant similarity to one another–save that investors have overreacted to the news. Savvy investors now have a great opportunity to pick up shares of Total at a bargain price and lock in a dividend yield of roughly 6 percent.

The G4 well that’s the source of the Elgin leak hasn’t been in production since February 2011. In fact, Total had been working to plug the well for permanent abandonment. More important, the Elgin gas field that the well targeted isn’t the source of the leaking gas, which Total has attributed to a limestone reservoir about 1,000 meters (3,100 feet) above the field.

Management has noted that the “tight” reservoir from which the gas is flowing lacks permeability, which should limit the amount of leakage relative to other major spills. In the case of the Macondo blowout, not only were the hydrocarbons flowing from the primary reservoir, but the geological pressures propelling oil and gas into the Gulf were also much higher because the field had been discovered relatively recently. 

The Elgin field, which was discovered in 1991, produces natural gas and condensate that doesn’t contain significant quantities of hydrogen sulfide, a toxic gas that would pose a significant challenge to workers seeking to stop the leak.   

The France-based oil company estimates that the leak is emitting roughly 7 million cubic feet of natural gas into the atmosphere each day. High winds in this part of the North Sea help to dissipate the gas more quickly than would otherwise be the case, while the site’s distance from shore poses little immediate threat to any population centers.

That being said, the leak has forced Total and other operators in the region to temporarily abandon activity and shut in production.

In addition to natural gas, Total estimates that the field has leaked between 5 metric tons to 9 metric tons per day of condensate into the water; this liquid hydrocarbon is the source of the sheen on the water that some news outlets have reported. Like gasoline, condensate evaporates more quickly than crude oil.

Assuming that the volume of condensate emitted into the North Sea is at the high end of Total’s estimated range, the flow rate equates to less than 70 barrels per day–not enough to cause significant long-term damage to the environment. To put the spill into context, oil gushing from the Macondo well peaked at 60,000 barrels per day to 70,000 barrels per day–about 1,000 times the rate at which condensate is leaking from the Elgin platform.

Whereas operators struggled to plug the blown-out Macondo because the source of the spill was almost 1 mile below the surface of the Gulf of Mexico, the hydrocarbons leaking into the North Sea are coming from equipment installed on the surface platform. Advanced robotic vehicles won’t be required for this operation.

Total has two plans to control the natural gas leak and is pursuing both courses simultaneously.

In a few weeks, the energy company could pump drilling mud, bits of rubber and metal into the top of the well to counteract the underground pressures that are pushing gas to the surface, enabling engineers to pump concrete into the well for permanent abandonment.

BP attempted this “top-kill” method on the Macondo well in 2010, but the extraordinary geologic pressure forcing the oil into the Gulf of Mexico was too strong to overcome. BP also struggled to achieve a solid seal on the top of the well, so much of the drilling mud spilled outward.

The reservoir pressures at Elgin should be far more manageable. With direct access via the platform, Total should have an easier time pumping mud into the well.

Total’s alternative effort to control the well involves drilling two relief wells that intersect the shaft of the G4 well and then pumping concrete in to plug the leak. BP used this technique to permanently plug the Macondo well. Such an approach would take months to complete.

This brings us to the question of cost. Total estimates that it’s losing about 53,000 barrels of oil equivalent per day of net production because the leak has forced the firm to shut production at nearby platforms. Management has assigned a price tag of about USD1.5 million per day to this lost production, while the cost of responding to the spill has been roughly USD1 million per day. Drilling the relief wells will ratchet up this expense to about USD1.5 million per day.

The firm will also likely face fines from the UK government and could be sued by Royal Dutch Shell (LSE: RDSA, NYSE: RDS A, RDS B) and other producers that have been forced to halt operations in the area.

Total shouldn’t have any problems paying these bills. One of the largest energy firms in the world, the company has $19 billion in cash on hand and about $10 billion in undrawn credit lines. In addition, the company has roughly $750 million in third-party insurance coverage for liability and more than $1 billion in coverage for property damage related to the Elgin spill.

Based on management’s initial cost estimates, the company has plenty of cash on hand to maintain its current dividend and fund planned capital expenditures for 2012. Management also indicated that the cause and magnitude of the spill are unlikely to usher in major changes to how wells are drilled in the UK portion of the North Sea.

In the unlikely event that Total needs to borrow money, the leaking well hasn’t affected the company’s bonds: The firm’s 2 7/8 percent maturing in 20122 currently yield 3.22 percent, one of the lowest yields to maturity of any 10-year bond issued by a large-cap European company.

In short, the Elgin spill shouldn’t present a major obstacle to Total’s growth story; the recent selloff in the stock appears overdone, especially when you consider the company’s myriad upstream growth projects around the world.

Upstream Growth

As one of the world’s largest energy companies, Total’s biggest challenge is growing its annual production. All upstream operators face waning output as their existing fields mature; to offset this natural decline rate, energy companies must locate and develop new oil and gas plays.

With a lower base of production, Aggressive Portfolio holding Oasis Petroleum (NYSE: OAS) and other smaller operators can post impressive production growth simply by drilling more aggressively. Total, on the other hand, flows about 2.35 million barrels of oil equivalent per day from its global operations; only large-scale projects and billions of dollars in capital expenditures can move the needle on the firm’s hydrocarbon output.

In recent years, Total’s declining production has been one of the main arguments against investing the company. Although the energy giant’s annual output has rebounded from its 2009 low of 2.28 million barrels of oil equivalent per day, this key metric still sits well under the 2.58 million barrels of oil equivalent per day that the firm lifted in 2004.

Source: Bloomberg

But Total last September outlined a credible long-term plan to grow its production at an average annual rate of 2.5 percent through 2015. The Super Oil has roughly 25 major oil and natural gas projects in the works that will add 600,000 barrels of oil equivalent per day in output to its portfolio by 2015. With Brent crude oil at $100 per barrel, management estimates that these endeavors will generate more than USD10 billion in cash flow over this five-year period.

These growth initiatives involve substantial investments in exploration and production, with the company in 2012 allocating USD20 billon of its USD24 billion budget toward upstream operations. Total’s planned expenditures on exploration and production represent an almost 18 percent increase from year-ago levels and are among the most aggressive of its peers.

These efforts are beginning to bear fruit. Total in 2011 announced the discovery of three giant oil fields (plays estimated to contain more than 500 million barrels of oil equivalent in reserves): the Zaedyus field in French Guyana, the Aquio-X1001 in Bolivia and the Absheron field in Azerbaijan. This marked Total’s best ever year in term of finding giant oil fields.

Tullow Oil (LSE: TLW) operates the Zaedyus prospect and late last year announced a major oil discovery from a well in about 6,000 feet of water. Tullow Oil also discovered the Jubilee oilfield offshore West Africa a few years ago and has backed up its theory that the fields offshore West Africa would feature geological characteristics to the massive oil and gas plays off the coast of Brazil.

More test wells will be necessary, but some estimate that this find could contain several billion barrels in reserves. Total has a 25 percent stake in the play and holds nearby acreage that also appears prospective for hydrocarbons. A major discovery like Zaedyus boosts the value of all acreage in the region because such a find lowers the risks of drilling a dry hole.

The Aquio discovery is located at the foot of the Bolivian Andes. Total has an 80 percent operating stake in the field, which produced natural gas and condensate at impressive rates in early well tests.

Finally, the Absheron discovery is located at a water depth of 1,500 feet in the Caspian Sea. Total operates this play and owns a 40 percent working interest in the field.

In aggregate, the company plans to drill or participate in a 60 exploratory wells in 2012 and 2013, with a heavy focus on prospects in Africa and South America.

Liquefied natural gas (LNG) accounts for about 27 percent of Total’s upstream results and is a major contributor to future production growth. As I explained at length in the previous issue of The Energy Strategist, investors must distinguish between the oversupplied US market and tight supply-demand conditions in international markets.

Whereas frenzied drilling activity in unconventional plays such as the Marcellus and Eagle Ford Shale has glutted the US market for natural gas and depressed prices to record lows, competition for LNG imports in Asia and Europe will intensify in the next several years. In Europe and Asia, LNG routinely fetches four to five times the prevailing price in the US market

About 70 percent of Total’s LNG production is committed to be sold at oil-indexed prices.

Total has increased its LNG output by 50 percent since 2009, and the firm has three major LNG projects under development.

1. The Australia-based billion Ichthys LNG project, which will produce 8.4 million metric tons of LNG per year and 100,000 barrels per day of condensate, is expected to cost USD34 billion and will come onstream at the end of 2016. Total owns a 24 percent stake in this project.

2. The France-based energy giant also holds a 13.6 percent interest in the Angola LNG project, which will begin operations at the end of 2012 and ramp up to 5.2 million metric tons of annual output.

3.  The Australia-based Gladstone LNG project, in which Total owns a 27.5 percent stake, is slated to start up in 2015 and produce up to 7.2 million metric tons of LNG per annum.

Total also has exposure to exciting deepwater projects in the US Gulf of Mexico, Asia and offshore South America. However, the firm’s particularly strong offshore Africa–a region in which it has a long operating history–offer the best growth prospects. Management expects the company to more than double its deepwater output between 2010 and 2020.

The Pazflor development off the coast of Angola is one of the largest in Total’s history. The company holds a 40 percent working interest in this play, with BP, ExxonMobil (NYSE: XOM) and Statoil (Oslo: STE, NYSE: STO) rounding out the stakeholders. Discovered in 2000 in waters that are 2,000 to 3,500 feet depth, Pazflor is a giant oil field that’s estimated to contain up to 590 million barrels of oil. Total began commercial production from the field in August 2011 and expects output to peak at roughly 220,000 barrels per day.

Meanwhile, Total’s downstream and petrochemical operations–both of which face headwinds–account for only 15 percent of the firm’s annual profits. Refineries in Europe have faced particular challenges because economic weakness has sapped demand for gasoline, while the elevated price of Brent crude oil has eroded profit margins. Management has launched a number of cost-cutting initiatives and expanded into Asia and the Middle East, regions where refiners enjoy superior profit margins and growth potential. Nevertheless, the firm’s limited exposure to the downstream segment gives it a leg up on the competition.

With a dividend payout ratio of 45 percent in 2011 and ample cash on its balance sheet, Total’s quarterly disbursement shouldn’t be threatened by the costs associated with the natural gas leaking from the Elgin platform. If Brent crude oil hovered around $80 per barrel for a prolonged period, the company would eventually be forced to reassess its dividend and/or capital spending plans–so would many oil companies. Fortunately, tight supply-demand conditions in the global oil market make it difficult to imagine such a scenario, especially after Brent crude oil remained above $100 per barrel at the height of panic about the EU sovereign-debt crisis.

At its current share price, Total is one of the cheapest major integrated oil stocks available and offers a dividend yield in excess of 6 percent, largely because of overblown concerns about the natural gas leaking from the Elgin field.


Source: Bloomberg

Total’s American depositary receipt (ADR) rates a buy up to USD57 and is new newest member of the Conservative Portfolio. I’ve also added the stock to my Best Buys list.

Note that thanks to a tax treaty between the US and France, the withholding rate for dividends paid to foreign shareholders is just 15 percent. These dividends can be claimed as a credit against your US taxes.

Chevron Corp (NYSE: CVX)

Conservative Portfolio stalwart Chevron Corp will host its quarterly interim update next Tuesday, an event that can be a market mover.

Regardless of news flow from this event, the long-term investment thesis for Chevron remains the same: reliable execution, a favorable production mix and a solid slate of attractive growth projects.

From the end of 2008 to the end of 2010, Chevron grew its overall production by more than 9 percent, a rate that surpassed many of its peers. This growth is particularly impressive when you consider that crude oil accounted for about 70 percent of the firm’s 2011 output–there’s an old saw in the energy business that it’s harder to grow oil production than it is to flow more natural gas. By comparison, natural gas accounted for about 50 percent of ExxonMobil Corp’s 2011 production.

Chevron is also the most profitable oil major on a cash-margin basis. In 2011 the company earned $38.86 per barrel of oil equivalent, compared to $25.68 per barrel of oil equivalent for ExxonMobil and $22.47 per barrel of oil equivalent for Royal Dutch Shell.

The company’s above-average production growth and profitability has also enabled its shares to outperform its peers: Chevron’s stock is up more than 66 percent over the past three years, while shares of ExxonMobil have generated a return of less than 30 percent for investors.

Past results don’t guarantee future performance, but Chevron’s current five-year plan suggests that the company’s winning streak will continue. Management expects total production to reach 3.3 million barrels of oil equivalent per day, an increase of almost 25 percent from the 2,680 million barrels of oil equivalent per day that the firm is expected to flow in 2012.

However, much of this projected growth will occur between 2014 and 2017. The near-term forecast is far more modest. In fact, management expects the firm’s total output to remain roughly flat in 2012.

Ironically, elevated oil prices contributed to Chevron’s declining production in 2011 and are expected to result in flat output in 2012.

Many of Chevron’s projects in international markets are production sharing contracts (PSC) with state-owned or partially state-owned entities. In exchange for access to Chevron’s vast experience and technical know-how, these local operators grant the Super Oil a cut of production.

These agreements are usually structured so that Chevron quickly recovers its costs and then earns a steady profit from ongoing production. Oftentimes, the volume of oil and natural gas attributed to Chevron in a PSC depends on the hydrocarbons’ value in the marketplace. In other words, higher oil prices might lead to the same or higher profits for Chevron, but the amount of production will be lower.

With Brent crude oil averaging $110 per barrel in 2011, Chevron booked less production than expected under its PSCs. At the company’s analyst meeting in March 2012, management once again assumed that Brent crude oil would average $79 per barrel when formulating its full-year production forecast for the next five years. The company may ultimately lower these targets if oil prices remain elevated.

Management is particularly bullish on the growth prospects for its deepwater production and has allocated 28 percent of its planned 2012-17 capital expenditures to these operations. Management expects output from deepwater developments to grow to 470,000 barrels of oil equivalent per day in 2017.

The company has three significant deepwater start-ups slated for 2012. The Usan field in Nigeria came onstream in February and should ramp up to 180,000 barrels of oil equivalent per day by early 2013. The second stage of the Agbami project (also in Nigeria) should extend the field’s production plateau of 250,000 barrels of oil equivalent per day for a few more years. Finally, the second phase of the Tahiti development in the US Gulf of Mexico should enhance output from a play that’s been in production since 2009.

Chevron has allocated 37 percent of its 2012-17 capital budget to LNG projects. These investments should enable the firm to more than double its output of liquefied natural gas to 460,000 barrels of oil equivalent per day in 2017, up from less than 200,000 barrels of oil equivalent per day. These projects will increase Chevron’s exposure to natural gas, though the company’s production mix will still be more oil-heavy than many of its peers. At the same time, all these LNG projects and most of the company’s existing natural gas production is sold at oil-indexed prices–a huge advantage.  

Chevron’s Angola LNG project will come onstream this year and deliver peak output of 175,000 barrels of oil equivalent per day. The firm’s Australia-based Gorgon (slated for 2014) and Wheatstone (slated for 2016) will account for the majority of the firm’s LNG production growth.

We continue to like Chevron’s long-term production growth and regard the stock as the cornerstone of any energy-focused portfolio. Chevron Corp rates a buy under 105 in the Conservative Portfolio.

But the stock has traded above our buy target for some time; I’m dropping Chevron Corp from my Best Buys list and replacing it with Total, which has superior upside potential in the near term.

EEni (Milan: ENI, NYSE: E)

Conservative Portfolio holding Eni has been one of the best-performing major oil stocks thus far in 2012, in part because of the Italian government’s declining borrowing costs.

At the peak of the EU sovereign-debt crisis last year, yields on Eni’s 10-year bonds topped 5.5 percent but have declined to 4.5 percent in the new year. In their haste to cut exposure to Italian equities, investors overlooked the fact that cash flow from the majority of Eni’s most don’t depend on the health of the domestic economy. Investors appear to have come to their senses now that Italy’s borrowing costs have declined.

Eni’s management recently outlined a solid long-term upstream development plan that should enable the firm to grow its production at an average annual rate of 3 percent through the end of the decade. That’s an impressive feat when you consider that most of the major have suffered declining or flat production in recent years.

The company has also made a number of promising finds offshore Mozambique that are estimated to contain a total of more than 40 trillion cubic feet of natural gas. Eni owns a 70 percent stake in this play and plans to build multiple trains to liquefy the natural gas for export. If the company makes additional finds, the site could grow into Africa’s largest LNG project.

Results from four additional test wells to be drilled this year could be a significant upside catalyst for the stock.

Eni also has a 30 percent working interest in a series of oil and gas discoveries made in the Barent’s Sea offshore Norway. With a number of additional wells due to be drilled this year, there’s plenty of upside for these Arctic finds.

Although Eni’s upstream operations boasts significant upside and asset disposals should enable the company to reduce its debt, the stock continues to trade at a significant discount to its peers and offers an industry-leading dividend yield of more than 6 percent. Eni’s ADR remains a buy under 52.