Producing Dividends

Our strategy during the past two summers involved taking advantage of economic uncertainty and worries about the EU sovereign-debt crisis to add shares of dividend-paying securities and lock in above-average yields. In particular, we spotlighted the selloff in shares of our favorite integrated oil companies as a buying opportunity.

This approach holds merit in the current environment, albeit with a slight twist. In the past, we’ve purchased discounted shares of ExxonMobil Corp (NYSE: XOM) as a short-term trade. We booked a 17.7 percent after holding the stock from Aug. 24, 2011, to Jan. 5, 2012, and netted a roughly 40 percent gain between July 2010 and June 2011. Today, the stock yields about 2.7 percent and fetches almost 10.6 times analysts’ consensus earnings estimate for the next 12 months–a lofty valuation.

At this juncture, shares of Conservative Portfolio holding Chevron Corp (NYSE: CVX) yield almost 3.5 percent and trade at a forward price-to-earnings (PE) ratio of about 8.0.

Our long-term investment thesis for Chevron remains unchanged: 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. 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 (LSE: RDS, NYSE: RDS A).

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. Much of this projected growth will occur between 2014 and 2017.

Although we regard Chevron as a foundational holding for every-focused portfolio and the stock trades below our buy target, some of its peers trade at lower valuations and offer superior yields. Chevron Corp rates a buy under 105 for any investors who haven’t added this long-term winner to their portfolios. Bargain hunters should buy if the stock dips to less than 95.

Today, shares of our favorite European integrated oil companies offer the best near-term upside and dividend yields, largely because of the ongoing weakness in their domestic stock markets and some company-specific uncertainties.

We added Total (Paris: FP, NYSE: TOT) to the Conservative Portfolio in the April 5, 2012, issue, shortly after news broke that leaking natural gas from a production site forced the company to shut-in operations in its Elgin and Franklin fields offshore Scotland. The company’s American depositary receipt (ADR) gave up almost 20 percent between March 23 and June 9, the stock’s recent low.

Recent news flow and comments from management suggest that investors have overreacted to the natural-gas leak, which Total plugged about a month ago. Not only did the disaster pale in comparison to the Macondo oil spill in terms of environmental damage–the natural gas dissipated into the atmosphere–but the Super Oil also has the financial wherewithal to survive the losses associated with the seepage.

Management estimates that response and remediation effort, which spanned roughly two months, cost the company about USD1.5 million per day before taxes and insurance. Meanwhile, the lost production from operations in the Elgin and Franklin fields amounted to about 50,000 barrels of oil equivalent per day, resulting in about USD1.5 million in lost operating income per day.

The firm will also likely face fines from the UK government and could be sued by Royal Dutch Shell and other producers that have been forced to halt operations in the area.

Total shouldn’t have any problems overcoming the estimated USD400 million in leak-rekated expenses. One of the largest energy firms in the world, the company has USD17 billion in cash on hand and about USD10 billion in undrawn credit lines. In addition, the company has roughly USD750 million in third-party insurance coverage for liability and more than USD1 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. In the first quarter, the company generated enough cash flow for a dividend coverage ratio of 36 percent, well below management’s long-term target of 50 percent.

During a conference call to discuss Total’s first-quarter results, CFO Patrick de la Chevardière acknowledged that uncertainty related to the leaking Elgin gas well had dissuaded the firm from hiking its interim dividend. However, the CFO also indicated that a higher payout remains in the company’s plans:

[W]hat we think about the dividend is that it was too early and that we need time to control the Elgin situation prior in deciding to increase the dividend. So it is not because we haven’t increased the dividend this time that we will not increase later on. We will see according to the situation. And I remind you that what we said in the past is that we have room to increase the dividend. This remains valid, but it’s just a matter of time.

Although these considerations likewise prevented Chevardière from providing updated production guidance for 2012, the CFO noted that each month of lost output from Total’s shut-in operations in the North Sea cost the firm 0.2 percent of its projected production growth. Management expects operations in the Elgin and Franklin fields to come back onstream gradually toward the end of the year, though this decision hinges on regulatory approval. In the event that the idled operations in the North Sea remain offline, management estimates that production will be flat relative to the prior year.

Nevertheless, Total’s long-term growth prospects remain intact. Management reaffirmed plans to grow output at an average annual rate of 2.5 percent between 2011 and 2015, fueled by a slate of about 25 projects that will add 600,000 barrels of oil equivalent per day to its portfolio.

With work on the second phase of the Ofon field development offshore Nigeria starting in February 2012, about 95 percent of the projects that management expects to contribute to this five-year production target are under construction.

Meanwhile, management noted that a number of projects came onstream during the first quarter, including the Usan oil field offshore Nigeria, the Islay gas field in the North Sea and the Greater Bangkot South gas and condensate field in the Gulf of Thailand.

Total’s future also looks bright beyond 2015. The international oil company 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 worth of 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.

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:

  • 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.
  • 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.

  • 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 (LSE: BP, NYSE: BP), ExxonMobil 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 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.

Investors’ overreaction to the natural-gas-leak in the Elgin field, coupled with general weakness in European equity markets, marks a prime opportunity to pick up shares of Total at a discount. Yielding 6.9 percent, Total’s ADR rates a buy up to USD57. With the stock market likely to suffer another leg down this summer, investors should consider easing into this position over the next few months.

One of Italy’s largest companies by market value, Conservative Portfolio holding Eni (Milan: ENI, NYSE: E) is in the midst of a restructuring that will increase the company’s exposure to exploration and production.

Some of this effort stems from governmental fiat. The Italian Cabinet in May 2012 decreed that Eni must sell much of its 52.5 percent controlling stake in Snam (Milan: SRG), which owns and operates the nation’s largest natural gas storage and distribution network. Since taking office, Prime Minister Mario Monti’s government has focused on liberalizing the nation’s gas distribution network and freeing up Snam to invest in other European gas grids. EU regulators had criticized Eni for blocking access to some pipelines and preventing supply from flowing to areas with the highest prices.

Eni on June 15 finalized the sale of a 30 percent interest in Snam (minus one share) to Cassa Depositi e Prestiti (CDO), the postal savings bank in which the government owns a 70 percent stake. The integrated oil company will receive EUR3.43 (USD4.31) for each Snam share, which equates to EUR3.517 billion. Snam will also have to repay Eni more than EUR11 billion in debt after the split, as the Super Oil formerly raised cash to meet the distribution company’s financing needs.

During a conference call to discuss the transaction, Eni’s CEO confirmed that the company will divest its entire equity stake in Snam and noted that the firm had received a number of unsolicited inquiries from institutional investors. Reuters recently reported that sovereign wealth funds from Abu Dhabi and Qatar had expressed interest in purchasing Eni’s remaining ownership stake, citing sources within the Super Oil.

The deal comes on the heels of a series of pipeline divestments to settle antitrust charges EU regulators had levied against the company and a March 29 agreement to sell a 5 percent equity interest in Galp Energia (Lisbon: Galp), Portugal’s largest oil company, to Amorim Energia for EUR14.25 per share. In a conference call to discuss Eni’s first-quarter results, management revealed that the firm had received unsolicited offers from financial institutions for another 18 percent to 20 percent stake in Galp Energia and expects a deal to close before year-end.

What are the implications of these divestments? Management estimates that the Snam sale would have reduced 2011 earnings before income and taxes by 12 percent but emphasized that the impact on free cash flow would be negligible. The move also enables the firm to allocate 60 percent of its budgeted capital expenditures to exploration and production, up from 50 percent in 2011.

With more than 60 major field developments expected to add about 700,000 barrels of oil equivalent production to Eni’s portfolio through 2015, management estimates that the firm’s hydrocarbon output will grow at an average annual rate of 3 percent over this period.

A series of impressive discoveries in 2011 also prompted Eni to increase its forecast for average annual production between 2015 and 2021 to 3 percent. Chief among these finds: An estimated 40 trillion cubic feet of natural gas in Area 4 of the Ravuma Basin offshore Mozambique, a block in which Eni owns a 70 percent ownership interest.

Over the next few years, management expects to invest about EUR400 million in additional well tests to further define the structure and generate a development plan that will start in 2018. This project will supply the local market and export natural gas in liquefied form. Other promising developments include two additional Yamal gas fields in Russia and the Kashagan play in Kazakhstan.

Eni’s long-term exploration plans include opportunities offshore west and east Africa, as well as a recent agreement with Rosneft (Moscow: ROSN) to explore for oil and gas in the Barents Sea and the Black Sea. Through a memorandum of understanding with China National Petroleum Corp, Eni is also evaluating shale oil and gas blocks on the Mainland.

The Italy-based energy giant’s gas and power segment (9.8 of 2011 revenue) has suffered from declining volumes because of reduced demand in Europe and price competition from liquefied natural gas. But Eni in recent years has renegotiated natural-gas supply contracts with major suppliers such as Libya’s national oil company, Sonatrach and Gazprom (Moscow: GAZP), moves that have helped to offset some of these challenges.

With the bulk of its revenue coming from exploration and production and a credible plan for output growth, Eni represents a solid bet for investors seeking growth and income. Management also recently reaffirmed the firm’s 2012 dividend and announced a share-buyback program.

However, investors should note that dividend growth may slow in coming years as the company shifts its focus to exploration and production. Yielding 6.6 percent and trading at a discount to its peer group, Eni’s ADR rates a buy under USD52.

Picking the Right Partners

Growth Portfolio holding Linn Energy LLC (NSDQ: LINE) is a limited liability company (LLC), an organizational structure similar to a master limited partnership (MLP), that owns oil- and gas-producing properties in the Permian Basin of west Texas, the Los Angeles basin of southern California, the Bakken Shale of North Dakota, the Midcontinent of northern Texas and Oklahoma and the Antrim Shale of Michigan.

Linn Energy’s business model is simple: The firm acquires mature oil- and gas-producing assets and hedges the majority of its production for five years into the future to lock in gains.

Linn Energy went public in 2006 and was among the first upstream partnerships to list on the major US exchanges since the 1980s. As a first mover, Linn is now the largest of the upstream partnerships and has superior access to capital, despite its B credit rating. This low cost of capital has allowed Linn Energy to make large acquisitions in recent years, including acreage in the Bakken Shale, a region where no other upstream MLP operates.

The other major distinction is that Linn Energy hedges its production aggressively, locking in prices on the majority of its output. This strategy limits Linn Energy’s to the depressed price of natural gas in North America and fluctuations in oil prices

Always opportunistic Linn Energy in February announced an agreement to acquire conventional gas fields in Kansas’ Hugoton Basin from BP for $1.2 billion. NGLs account for about 37 percent of output from these properties, with natural gas making up the remaining 63 percent.

Although natural gas prices remain depressed in North America, Linn Energy  purchased these properties at a price that makes the transaction immediately accretive to distributable cash flow. Moreover, the limited liability company disclosed that it has hedged 100 percent of the acreage’s expected natural gas production and 68 percent of its NGL output over the next five years. This move limits the firm’s exposure to unfavorable swings in commodity prices

The firm also closed a $400 million joint venture with Anadarko Petroleum Corp (NYSE: APC) in early April and the $175 million acquisition of properties in East Texas shortly thereafter.

This is the fastest pace of acquisitions for Linn Energy in some time, and all these deals should be immediately accretive to cash flows. The company has very little commodity or economic risk, thanks to its aggressive hedge book.

We expect additional bolt-on acquisitions in the firm’s operating regions to fuel distribution growth in coming years. Yielding more than 8 percent at current prices, units of Linn Energy LLC rate a buy under 40.

We added Mid-Con Energy Partners LP (NSDQ: MCEP) to the Growth Portfolio on Feb. 2, 2012, about two months after its initial public offering. With a market capitalization of only $362.9 million and an average daily trading volume of about 66,000 units, the stock has endured significant volatility over the past few months.

With the EU sovereign-debt crisis roiling the stock market and another growth scare weighing on oil prices, investors should expect the unit price of Mid-Con Energy Partners to fluctuate in coming months. That being said, results from Mid-Con Energy Partners’ first full quarter as a publicly traded firm reaffirmed our confidence in the upstream MLP’s growth story and suggest that the stock will reward investors who stick it out for the long term.

Mid-Con Energy Partners owns about 10 million barrels of oil-equivalent reserves in the Midcontinent region, 69 percent of which are proved and developed. Crude oil accounts for about 96 percent of the firm’s reserves, a favorable mix in the current price environment. Like many upstream MLPs, the firm operates in established plays that feature limited drilling risk and predictable decline rates.

In fact, management estimates that about 90 percent of the outfit’s wells have been in production since 1982 or earlier. Mid-Con Energy Partners specializes in water-flooding, an enhanced recovery technique that involves injecting large volumes of water into a mature field to restore well pressure and bolster output. So-called primary production recovers only 10 percent to 25 percent of the hydrocarbons in a field, while water-flooding and other secondary techniques can extract another 10 percent to 20 percent of resources in place.

More than 90 percent of Mid-Con Energy Partners’ producing wells employ water flooding to improve production rates. Six to 18 months of water injections are required to increase production, but the technique works. The MLP’s acreage in southern Oklahoma (about 55 percent of total reserves), which is still in the early stages of water-flooding, flowed about 220 barrels of oil equivalent per day in September 2006 and in December 2011 yielded 2,492 barrels of oil equivalent per day.

During the first quarter, Mid-Con Energy Partners extracted 1,703 barrels of oil equivalent per day–150,000 barrels of oil and 31 million cubic feet of natural gas–up 15 percent sequentially. Excluding derivatives related to hedging, the MLP’s hydrocarbon sales totaled $15.5 million, while the firm’s adjusted earnings before interest, taxes, depreciation and amortization came in at $11.8 million. More important, Mid-Con Energy Partners generated distributable cash flow of $0.556 per unit, enough to cover the quarterly payout by 1.17 times. Over the long term, the MLP targets a payout ratio of between 1.15 and 1.20 times.

With management expecting daily production to average 1,850 barrels of oil equivalent per in 2012 and 75 percent of this output hedged at favorable prices, we expect the recent weakness in oil prices to have only a modest effect on the MLP’s near-term fortunes.

Moreover, Mid-Con Energy Partners’ growth story remains intact. In April, the company increased its borrowing base to $100 million, an amount that management told analysts would “cover any potential acquisitions for the year, but not [include] any unused availability that [the firm] wouldn’t need.”

CEO Jeffrey Olmstead also indicated that the pipeline of potential acquisitions and joint ventures appears strong, with many exploration and production companies seeking to divest mature assets to fund drilling in shale basins and other emerging plays:

As far as opportunities arise, our deal flow really in the last six months has been as good as it has ever been. We’ve looked at more water-flood opportunities–…from grass roots [opportunities] that our people have put together themselves and gone out and found, to companies that maybe have come across some water-floods and some acquisitions they had that [weren’t] their core competency…[Some companies] have talked about divesting [these properties] and that other people talk to us about joint venturing with them. So, we’re very positive on the outlook in the deal flow that we’ve seen and hope to continue to grow with it.

Even if Mid-Con Energy Partners doesn’t close an acquisition in 2012, management reaffirmed that 2013 will likely bring a drop-down transaction from the firm’s general partner, private-equity outfit Yorkville Partners.

Mid-Con Energy Partners’ parent, which has about $3 billion in assets under management, has invested in a number of oil- and gas-producing properties that might be a good fit for Mid-Con Energy Partners. Private affiliate Mid-Con Energy III focuses on water-flood opportunities that fit the MLP’s business model, while Mid-Con Energy IV targets primary production opportunities over a broader geographic range. Management indicated that any drop-down transactions in the near-term would likely come from Mid-Con Energy III.

By dropping down a new water-flooding project to Mid-Con Energy Partners, Yorktown Partners would monetize this asset and shield ongoing revenue from the field from corporate taxation. Meanwhile, rising production and cash flow from the dropped-down asset would enable Mid-Con Energy Partners to grow its distribution. With an almost 50 percent stake in Mid-Con Energy Partners’ outstanding units, Yorktown Partners has ample incentive to pursue strategies that will foster the MLP’s growth.

Prospective investors should also note that management reviews Mid-Con Energy Partners’ distribution policy every third quarter, so the payout will likely increase once annually rather than in incrementally in each quarter.

Mid-Con Energy Partners’ oil-weighted production mix and solid pipeline of growth opportunities makes the stock a buy under 26.50. Investors who can stomach the volatility should jump at any chance to acquire the stock for less than $19 per unit and lock in a roughly 10 percent yield.

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