In Review
Macro events continue to drive global equity markets, including energy stocks. The primary concerns of the day include softening global economic data and renewed concerns that the Greek government could default on its massive debts.
Despite the negative headlines in the financial press, the S&P 500 slipped only modestly in May and early June. But over the past two weeks the broader market has sold off even on slow news days. Individual names have also pulled back after announcing positive developments. Nevertheless, the S&P 500 has pulled back only 5.6 percent since May 1, compared to a 9.6 percent decline over the same period last summer. Investors should expect the market to trade lower or sideways for a bit longer.
Regardless of its duration, this summer swoon remains an excellent buying opportunity.
Although my holiday in Santorini, Greece (for pictures, check out my Twitter account) hasn’t been interrupted by the recent protests in a handful of cities, I did catch a TV broadcast Prime Minister George Papandreou’s speech to parliament before the confidence vote took place. My command of the local language isn’t the best, but I could tell that Papandreou did not sound as though he was ready to give up the fight for his proposed austerity measures.
After the prime minister won the confidence vote, odds favor the passage of additional budget cuts and further aid from the EU and the International Monetary Fund, both of which should stave off the threat of default.
Still, Greece will face significant hurdles in coming years, from passing a fourth round of austerity measures to gradually restructuring the national economy. But don’t let the sensationalist stories in the US media dissuade you from visiting the country this summer–the nation hasn’t descended into utter chaos. In fact, all of my flights into and out of Athens were more punctual than my flights from Washington, DC. At this point, the protests have been confined to the city center.
The purported deaths of the EU and the euro are also greatly exaggerated. If the EU were on the verge of collapse, would the currency still trade for USD1.44?
Last summer, we repeatedly told readers that the challenges in peripheral economies such as Greece and Ireland wouldn’t send the rest of the EU spiraling into recession. If Greece were to default on its sovereign debt, the market worried that global credit markets might freeze once again.
Although the situation in Greece bears watching, Italy and its USD2.11 trillion economy pose a much larger risk. Despite Italy’s high debt-to-GDP ratio, its government is in much better fiscal health than Greece. The Italian government has reduced its budget, but doesn’t require the magnitude of cutbacks that its Mediterranean counterpart must endure to get its fiscal house in order. Italy’s economy hasn’t slipped into recession. Moreover, Italy’s budget deficit this year will be among the lowest in the EU.
The second act of the Greece’s sovereign debt drama has raised the cost of credit default swaps (CDS) for Italian government bonds. But at 175 basis points, five-year CDS on Italy’s sovereign debt trade remain well short of the levels that prevailed during the Irish debt crisis.
This contagion has yet to affect the US credit market. For example, the TED spread–the difference between the London Interbank offer rate and the yield on short-term Treasury bills–stands at just 22 basis points, less than half its 2010 high. US corporations continue to sell bonds, paying interest rates that represent near record-low spreads over Treasuries.
Finally, recent data suggests that the US economy may be emerging from its recent soft patch.
Source: Bloomberg
This Citigroup US Economic Surprise Index compares the consensus estimate for key economic data to the actual figures. Negative numbers indicate that economic data has consistently come in below expectations.
As you can see, data came in well under consensus outlooks starting in April, when the index plummeted to a multiyear low. But last week US economic data–including jobless claims and retail sales–largely beat the consensus expectations. Although it’s too early to claim definitively that the US economy has turned the corner, this could be the first sign that supply-chain disruption stemming from the earthquake in Japan’s Tohoku region have begun to abate. Lower oil prices should also provide some relief to US consumers.
Regardless of whether this improvement proves durable, the data suggests that the US economy isn’t at risk of slipping into a recession.
The latest summer swoon should follow the pattern established in 2010. Expect concerns about the EU sovereign debt crisis and a US economic slowdown to fade as the summer progresses. Meanwhile, the ongoing correction in the stock market offers investors a great opportunity to buy our favorite energy stocks at attractive prices.
Although macro concerns continue to dominate the tape, investors should never lose site of the outlook for their holdings. In this issue, we revisit our investment thesis for 14 of our model Portfolio holdings and review each name’s growth prospects. This exercise should bring new readers up to speed with our picks and provide longtime readers with piece of mind.
In This Issue
The Stories
Macro developments may be driving the stock market, but it’s important not to lose sight of company- and industry-specific fundamentals. We revisit our investment theses for 14 holdings in the model Portfolios. See Wildcatters, Proven Reserves and Gushers.
Want to know what to buy now? Check out the Fresh Money Buys list. See Fresh Money Buys.
The Stocks
BG Group (LSE: BG/, OTC: BRGYY)–Buy < GBp1,650 or USD133
Cameron International Corp (NYSE: CAM)–Buy < 62
Core Laboratories (NYSE: CLB)–Buy < 105
Dresser Rand Group (NYSE: DRC)–Buy < 55
Eagle Rock Energy Partners LP (NSDQ: EROC)–Buy < 12
Linn Energy LLC (NSDQ: LIBE)–Buy < 40
Peabody Energy Corp (NYSE: BTU)–Buy < 72.59
Suncor Energy (TSX: SU, NYSE: SU)–Buy < USD48
Chevron Corp (NYSE: CVX)–Buy < 105
Enterprise Products Partners LP (NYSE: EPD)–Buy < 45
ExxonMobil Corp (NYSE: XOM)–SELL
Oasis Petroleum (NYSE: OAS)–Buy < 37
Petrohawk Energy (NYSE: HK)–Hold
Valero Energy Corp (NYSE: VLO)–Hold
Wildcatters
BG Group (LSE: BG/, OTC: BRGYY) operates three business segments–liquefied natural gas (LNG), exploration and production (E&P) and transmission and distribution (T&D)–each of which offers exposure to a number of near- and long-term catalysts.
The firm’s LNG operations, which include liquefaction and re-gasification assets as well as the purchase, shipment, marketing and sale of LNG, accounted for roughly 35 percent of the company’s 2010 revenue. BG’s LNG operations and assets span the globe and, in many instances, complement its E&P efforts.
How do these disparate assets work within BG’s business model? BG’s LNG trading and shipping divisions work together to market, sell and deliver LNG volumes to customers worldwide on both a short- and long-term basis. In addition to marketing its own contracted LNG, the firm also buys volumes on regional spot markets and resells this gas to take advantage of regional pricing discrepancies. To support these trading activities, the company’s shipping arm boasts a fleet of owned and contracted ships.
Over the long term, BG’s extensive global operations should enable the firm to benefit from a global LNG market where demand growth outstrips constrained supply. In 2010 nations such as Spain, Belgium and the UK absorbed much of the LNG supply overhang that persisted after the global recession weakened demand and the ongoing shale gas revolution transformed the US market into an outlet of last resort.
LNG figures to become an increasingly important part of the Continent’s energy mix. Supply constraints, the planned decommissioning of nuclear reactors in Germany and a desire to limit reliance on Russian natural gas should prompt EU nations to build out the necessary cross-border pipeline and support infrastructure.
But the Asia-Pacific region–where long-term, oil-indexed contracts are the norm–represents the most exciting growth opportunity for BG. Management underscored this point during its Feb. 8 conference call to discuss the company’s 2010 results and outlook, noting that the use of oil for heating purposes provides ample opportunity for fuel substitution. High economic growth in Asian emerging markets should continue to drive robust demand among industrial, commercial and residential consumer segments.
Natural gas currently accounts for only 4 percent of China’s energy mix, but BG estimates that an increase of 1 percent in gas penetration adds 25 billion cubic meters per year to Chinese gas demand. That’s equivalent to the total output from four liquefaction trains at BG’s massive Queensland Curtis LNG (QCLNG) Project in Australia.
Management also noted that if gas penetration in China were to approach the levels in India–still low by global standards–Chinese gas demand would increase by roughly 150 billion cubic meters per year, or about 1.5 times Qatar’s LNG production capacity. For those wondering about this seemingly obscure comparison, Qatar is the world’s leading producer of LNG.
Based on management’s forecast for Chinese LNG demand growth and the likelihood of new markets coming online, global demand will likely eclipse the current consensus projection of 350 mtpa in 2020. At present, only 280 mtpa of liquefaction facilities are in operation or have been sanctioned for construction. With its low-cost supply base and global operations, BG is well-positioned to benefit over the long term from tightening in international LNG markets.
For one, management forecasts that once QCLNG comes online, 75 percent of the firm’s LNG sales will be based on oil prices.
BG’s E&P division includes operations in the UK and Norwegian portions of the North Sea as well as stakes in emerging plays offshore Thailand, India, China and Tanzania. But the crown jewel of the company’s E&P operations are its interests in six blocks offshore Brazil, in the highly prospective Santos Basin.
Expanding production, coupled with resource upgrades and new discoveries offshore Brazil, should provide plenty of catalysts for BG’s shares over the next few years. In the near term, drilling activity offshore China and Tanzania could provide further upside.
BG’s transmission and distribution operations are concentrated in Brazil and India, two emerging markets where demand for natural gas-fired power plants will continue to grow as their economies expand.
The stock pulled back after the company posted first-quarter earnings that fell short of analysts’ consensus estimate and volume growth also disappointed. Nevertheless, the company’s mid- to long-term growth story remains intact. Buy BG Group under GBp1,650 on the London Stock Exchange or USD133 in the over-the-counter market.
We added Cameron International Corp (NYSE: CAM) to the Wildcatters Portfolio in an Oct. 13, 2010 Flash Alert, citing the stock’s attractive valuation and the company’s exposure to an uptick in offshore and deepwater drilling activity. Thus far, our investment thesis has yet to pan out: The stock is up only 7.5 percent over our holding period, underperforming the S&P 500 by almost 3.2 percent and the Philadelphia Oil Services Index by 13.1 percent.
First-quarter earnings per share were 17 percent shy of Wall Street’s consensus estimate, sapping the stock’s upward momentum and raising concerns about the timing of a turnaround in the company’s long-cycle business lines. Some investors worry that the company could suffer a lull in order bookings if sales of its short-cycle products begin to ease and demand for its long-cycle products doesn’t kick in immediately.
Despite these short-term concerns, Cameron International’s diverse business footprint and exposure to key secular growth trends in offshore and deepwater drilling make the stock an excellent pick for investors seeking long-term growth. Six of Cameron International’s 11 business lines offer exposure to deepwater the space, and the company holds the No. 1 or No. 2 market share in the majority of its product categories. Meanwhile, the firm usually generates about two-thirds of its revenue outside North America.
Cameron International operates three business segments: drilling and production systems (60.6 percent of 2010 revenue), valves and measurement (20.8 percent), and compression systems (18.6 percent).
Investors tend to focus on the drilling and production systems segment, which includes drilling systems, offshore systems and surface systems. Although the company’s surface (onshore) sales benefited from robust demand in US shale plays, the offshore segment is the star of the show because of the potential for huge project awards.
Management has indicated that it expects major project awards over the next six to 18 months offshore Brazil, West Africa, Australia and Asia-Pacific, but acknowledged many project awards have been delayed. This could be a boon for sales of the company’s subsea equipment, which include trees, wellheads and controls among other items.
The Macondo oil spill in the Gulf of Mexico ironically gifted Cameron International with a new growth opportunity, though the failure of blowout preventer (BOP) that it manufactured was a big part of the disaster.
A BOP is a large, heavy device that’s installed directly on the seafloor above a deepwater well during the drilling process and removed after the well is completed. The BOP is an emergency mechanism that, once activated, seals off a well and prevents hydrocarbons from escaping by ramming a rod with a rubber seal into the well. These devices include several backup mechanisms.
Cameron International’s BOPs boast an installed base of roughly 50 percent on offshore rigs; new rules requiring original equipment manufacturers to service this equipment on a regular basis should bolster the company’s aftermarket revenue. Nevertheless, some analysts have noted that competitor National Oilwell Varco’s (NYSE: NOV) BOPs appear to be winning share in the new sales market.
An uptick in orders for floating production, storage and offloading (FPSO) vessel such as those used offshore Brazil would be a boon for the company, particularly the firm’s valves and measurement business. Much of these orders would come from projects offshore Brazil and West Africa. Cameron International’s Cynara membrane technology, which it added to its portfolio when it acquired NATCO in 2009, could help solve the carbon dioxide separation challenges Petrobras (NYSE: PBR) has encountered in its pre-salt fields.
With $1.8 billion in cash on its balance sheet and an undrawn credit facility, Cameron International can afford to invest in future growth. The firm already boasts the only facility in the African nation of Angola that can design, assemble and test subsea equipment, and plans to invest considerable amounts to boost its presence in Brazil.
Cameron International rates a buy up to 62 for growth-oriented investors with a longer time horizon.
Netherlands-based Core Laboratories (NYSE: CLB) provides a range of services and solutions that enable oil and natural gas producers to maximize a energy output throughout a field’s life cycle. The company operates three business segments:
In the first quarter, spending in international markets failed to pick up measurably, limiting year-over-year revenue growth in the company’s reservoir description business to 3 percent. Nevertheless, management affirmed that it expects spending on exploration and production to increase at least 10 percent in international markets.
During Core Labs’ conference call to discuss first-quarter earnings, CEO David Demshur cited this slow turnaround and unrest in the Middle East and North Africa as the reasons for the company’s conservative guidance for the second quarter.
Meanwhile, the company’s production enhancement division grew revenue by 19 percent from a year ago, despite inclement winter weather that shut down drilling activity in certain US shale oil plays. However, these delays did weigh on margins, which declined by 200 basis points to 28 percent.
The unit’s results were bolstered by a project to monitor the water and gas flooding of a field offshore West Africa. Strong North American demand for the company’s HTD Blast firing system, which increased its market share to 19 percent from 17 percent in the fourth quarter, also boosted revenue. This technology, which increases the effectiveness of hydraulic fracturing, has proved popular in the Bakken and other shale oil fields.
Finally, the firm’s reservoir management division generated 10 percent more revenue in the first quarter than it did a year ago, with margins improving 300 basis points to 39 percent. In the first three months of the year, the firm kicked off a consortium study of the Avalon oil play, which encompasses parts of New Mexico and West Texas. Thirty-seven companies have now signed on to participate in the company’s Eagle Ford study, data from which will enable producers to maximize ultimate recovery rates.
Although a broader pullback in oil services stocks and Core Labs’ conservative guidance for the second quarter have weighed on the stock, our investment thesis remains intact.
The end of easy oil has forced producers into the deepwater and other expensive-to-produce plays, increasing demand for Core Labs’ reservoir description services. Given the service intensity and expenses required in these fields, producers are eager to pony up for the company’s reservoir description services, which can expedite the exploration and development process and limit costs during this phase. At the same time, the company’s production enhancement business should benefit from efforts to maximize output from producing wells.
These upside drivers could make Core Labs an attractive takeover target for a larger services firm. Buy Core Laboratories up to 105.
Dresser Rand Group (NYSE: DRC) is among the largest global suppliers of turbines, compressors and other high-speed rotating equipment primarily to the oil, natural gas and petrochemical industries. Oil- and gas-related markets accounted for roughly 83 percent of the firm’s 2010 sales, but the company’s products are also used by the US Navy and the paper, steel, sugar and power generation industries.
The company’s products are key components in all three segments of the energy patch: upstream (exploration and production), midstream (pipelines and storage facilities) and downstream (refining and marketing). For example, oil production ceases if a compressor stops pumping gas into a well, while a failed compressor will prevent a pipeline from transporting natural gas.
Dresser Rand divides its business into two segments, each of which accounted for about half the firm’s annual revenue in 2010: new-unit sales and aftermarket services.
New-unit sales should continue to benefit from a cyclical recovery in spending on exploration and production and investment in oil- and gas-related infrastructure.
In the upstream category, the company’s biggest growth opportunities are in offshore and deepwater markets, particularly in FPSO vessels and liquefied natural gas (LNG)-related infrastructure.
For example, Dresser Rand already delivered the world’s highest-density compressor to Japanese shipbuilder Modec (Tokyo: 6269, OTC: MDIKF) as part of an FPSO ordered by Brazilian national oil company Petrobras. A replacement for expensive carbon-dioxide pumps, this technology occupies less space on the vessel and reduce costs by USD5 to USD10 billion.
Once perfected and modified for subsea applications–to maximize output from mature fields, producers often put the compressor on the seafloor–this innovation could enable Dresser Rand to grow its share of the rapidly growing offshore drilling market.
Meanwhile, the company has also established a strategic alliance with Samsung Heavy Industries (Seoul: 010140) to provide compressors for LNG import and export projects as well as floating LNG rigs–imagine a mobile, offshore liquefaction facility. This agreement should enable the company to place its product on the many LNG-related projects on which Samsung Heavy Industries works.
Better still, once these new units are in place, the company enjoys a reliable revenue stream (and higher margins) from aftermarket service and parts. At present, management estimates the installed base of its compressors at almost 100,000 units–four times the amount of its closest competitor. The more units the company sells, the more follow-up revenue its aftermarket business will generate.
In the midstream space, Dresser Rand stands to benefit from rising demand for pipelines, processing plants and other energy infrastructure in both developed and emerging markets. In the US, for example, the rapid development of shale oil and gas fields necessitates massive investment in supporting infrastructure, much of which will require compressors.
In the downstream space, management estimates that the company has the opportunity to sell $50 million worth of equipment for every 200,000 barrels per day of refining capacity added in emerging markets.
Over the past decade, management has reoriented Dresser Rand’s business strategy to better reflect the growing importance of national oil companies and rising demand for energy infrastructure in emerging markets such as offshore Brazil and West Africa. The company continues to invest in expanding the global reach of its service centers, particularly in Brazil and the Middle East. Because of these efforts, Europe and North American accounted for only 56 percent of the firm’s 2010 revenue.
In recent years, the company has courted business in the environment services sphere, including waste-to-energy solutions, wind energy, energy storage and clean coal. Management has assured investors that many of its opportunities in this space don’t depend on government subsidies.
With exposure to attractive growth markets and an order backlog that suggests 2012 could be a record year for sales, Dresser Rand rates a buy up to 55.
Eagle Rock Energy Partners LP (NSDQ: EROC) is a master limited partnership (MLP) that operates two businesses: gathering and processing (G&P) and upstream.
Upstream operations involve the production of crude oil, natural gas and natural gas liquids (NGL) from the partnership’s properties in Texas and southern Alabama. In 2010 Eagle Rock Energy produced slightly more than 5,000 barrels of oil equivalent per day (boepd) from 273 operated wells and 137 non-operated wells in which the MLP owns an interest.
The G&P business consists of 5,500 miles of gathering pipelines in the Texas Panhandle, east Texas and Louisiana, south Texas, the Gulf of Mexico and west Texas. These small-diameter pipelines connect individual wells to processing facilities and, ultimately, the US interstate pipeline network. The firm also owns 19 gas processing plants that separate NGLs such as propane and ethane from raw natural gas; these plants are typically associated with Eagle Rock Energy’s gathering systems. In 2010 the firm gathered an average of 500 million cubic feet of gas equivalent per day and processed just over 300 million cubic feet per day.
Having passed one of the most difficult stress tests in its history, Eagle Rock Energy looks poised for significant growth over the next 18 months. In late 2008 and early 2009, plummeting natural gas prices prompted producers to rein in drilling activity, reducing throughput on Eagle Rock’s gathering systems. Meanwhile, the collapse in commodity prices also lowered profit margins in the firm’s processing business, which earns additional fees based on the sale price of NGLs and natural gas.
These trying times forced management to slash the firm’s quarterly distribution to the bone.
Although natural gas prices remain depressed, drilling activity continues apace in the nation’s liquids-rich shale plays; throughput volumes on Eagle Rock Energy’s gathering systems has recovered fully. Meanwhile, higher NGL prices have bolstered profit margins in the company’s processing business.
But management has also taken key steps to reduce its G&P segment’s exposure to commodity prices. The firm also undertook a restructuring effort that lowered its debt burden and eliminated the need to pay incentive distribution fees to the partnership’s general partner.
In light of these changes, we upgraded Eagle Rock Energy to a buy in a Flash Alert issued on June 10, 2010. Since then, the stock has generated a total return of 143 percent.
Eagle Rock Energy’s now has a solid platform for growth in both of its business lines. The firm’s G&P assets serve NGL-rich fields, which helps offset weak natural gas prices.
As the price of a barrel of NGLs tends to follow crude oil more closely than gas, producers with significant exposure to liquids-rich gas plays enjoy strong drilling economics. Several US-based petrochemical producers also have announced plans to build or expand their capacity to produce ethylene and propylene–the building blocks of many plastics–from NGLs. Meanwhile, US NGL exports have also hit record levels.
All of this adds up to higher throughput and profit margins for Eagle Rock Energy’s G&P assets.
The firm’s Texas Panhandle system serves the Granite Wash, a field that several producers are targeting using a combination of horizontal drilling and hydraulic fracturing techniques. The field produces extremely wet natural gas volumes–gas that’s high in NGL content–along with significant volumes of high-value condensate and some crude oil.
Given that liquids-rich mix, about 66 rigs operated in the play as of the end of the first quarter. Volumes of NGLs processed and recovered declined because of unusually cold winter weather in the first quarter of 2011, but that dip will give way to strong growth later in the year.
Another promising region for Eagle Rock Energy’s midstream business is its East Texas system, which serves the liquids-rich Austin Chalk. In the first three months of 2011, volumes gathered in the region increased by 3 percent from the previous quarter, while NGL and condensate volumes jumped 6 percent over this period.
The main growth driver in Eagle Rock Energy’s upstream business will be the $530 million acquisition of the Crow Creek properties in Oklahoma, Texas and Arkansas. This deal illustrates how far Eagle Rock has come over the past year and a half: A company once considered near bankruptcy closed a major acquisition and raised $300 million in capital via a bond offering that currently yields 8.5 percent.
When the transaction closed in May 2011, Eagle Rock Energy’s oil and gas reserves jumped by 200 percent from the end of 2010. The deal has also decreased Eagle’s exposure to natural gas production and increased the partnership’s focus on NGLs and condensate output.
Management has also stepped up its hedging program to lock in favorable market prices for oil, NGLs and natural gas. The partnership has hedged 80 percent of its 2011 natural gas production and 69 percent of its liquids output. In 2012 about 70 percent of the firm’s natural gas and liquids production has been hedged.
Based on the recent acquisitions and growth in midstream volumes, Eagle Rock Energy expects to boost its distribution to an annualized rate of $0.75 by the end of the second quarter and $1 per unit by the end of 2012–a substantial increase from the current annualized payout of $0.60.
Improving fundamentals and a growing distribution make Eagle Rock Energy Partners LP a buy under 12.
Linn Energy LLC (NSDQ: LINE) is a limited liability company (LLC), an organizational structure similar to an MLP, with producing properties in six distinct areas: the Permian Basin of West Texas, the Los Angeles basin of Southern California, the Bakken Shale of North Dakota, the Permian Basin of West Texas, the Midcontinent of Northern Texas and Oklahoma and the Antrim Shale of Michigan.
The Midcontinent and Permian are the two most important regions, accounting for a bit over 80 percent of the firm’s total reserves. Oil and NGLs account for about 55 percent of total reserves; natural gas accounts for the remaining 45 percent.
Linn Energy’s business model is simple: acquire mature oil and gas-producing assets and hedge the majority of their 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; recently, the partnership issued 10-year bonds offering a yield of less than 7 percent. That’s an impressive rate, especially when you consider Linn’s single-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 MLPs operate.
The other major distinction is that Linn is aggressive in hedging its production. While other upstream partnerships like EV Energy Partners LP (NSDQ: EVEP) and Legacy Reserves LP (NSDQ: LGCY) hedge a portion of their output, Linn Energy has hedged the majority of its output. That’s especially important for natural gas, as prices should remain depressed because of strong production from the nation’s shale fields.
The firm didn’t increase its distribution in its first-quarter earnings announcement. The numbers themselves, however, continue to point in that direction later this year. Distribution coverage came in solidly at 1.15-to-1, as the company continued to complete acquisitions to boost reserves and output, particularly on the liquids side.
Management guidance is now for 1.40-to-1 distribution coverage by profit for all of 2011. That, in CEO Mark Ellis’ words, “should provide us with the ability to increase our distribution this year.”
First-quarter output rose to 312 million cubic feet per day of natural gas equivalent, a 46.5 percent jump from year-earlier levels. The average selling price of $86.24 per barrel of oil equivalent is well below current spot market prices. Operating expenses per unit of production were flat year-over-year, while transportation expenses fell 12.5 percent per unit produced. Both are remarkable achievements for any company expanding this rapidly, particularly in liquids, where prices are much higher than for gas. Buy Linn Energy LLC under 40.
By the end of this decade, Suncor Energy (TSX: SU, NYSE: SU) expects its Canadian oil sands division to account for three-quarters of the firm’s total cash flows. The remaining third will come from its offshore and international operations.
Management has set forth an aggressive plan for production growth, targeting 1 million barrels per day in annual output by the end of the decade. This goal implies annualized production growth of 8 percent over the next decade. Most of the growth will come from its oil sands operations, which management expects to grow its output at a 10 percent annualized rate.
Another major advantage for Suncor is that more than 90 percent of its total production is oil, not natural gas or NGLs. Over the past year, the firm has disposed over more than $3.5 billion worth of noncore assets, including a number of gas-producing properties. In the current environment of high international oil prices and weak US gas prices, Suncor’s oil-heavy portfolio is a winning bet.
Management recently finalized an agreement on a strategic joint venture with France-based integrated oil giant Total (NYSE: TOT). Under the terms of the deal, Suncor swapped a 19.2 percent stake in its Fort Hills oil sands production project for a 36.75 percent stake in Total’s Joslyn project in Canada. Total, an experienced player in the oil sands in its own right, will continue to operate the Josyln project; Suncor will continue to run the Fort Hills project.
Suncor also sold a 49 percent stake (retaining the majority) in its Voyageur upgrader in Canada. Production from oil sands mining projects consists of a product known as bitumen, an extraordinarily heavy, viscous hydrocarbon. Bitumen trades at a sizeable discount to crude oil because it’s tougher to refine and requires expensive treatment before it can be converted into refined products such as gasoline or jet fuel. An upgrader can convert bitumen into synthetic crude oil, a product that is similar to standard light, sweet crude oil. As you might expect, synthetic oil trades at a substantial premium to bitumen.
The Voyageur upgrader will ultimately have capacity of about 200,000 barrels per day (102,000 barrels per day for Suncor’s share), and is expected to be put into service by 2016. Upgraders are a key part of the oil sands production process, but are also extremely expensive to build. By partnering with Total–a company nearly twice Suncor’s size–the firm company reduces its capital commitments. All told, Suncor picked up USD1.75 billion in cash and about 160 million barrels in high-quality oil sands reserves from the joint venture with Total.
To meet its ambitious production goals, Suncor has announced eight major projects that will take place in the oil sands.
Source: Suncor Energy
Like any other major mining project, oil sand projects are subject to delays from time to time; however, the addition of Total as a partner increases the chances Suncor will complete projects on schedule. Meanwhile, near-term projects–including Firebag 3 and 4–appear to be progressing according to management’s master plan. In 2011 the company aims to grow its oil sands output to as much as 310,000 barrels of oil per day, up from about 280,000 barrels per day in 2010.
Take advantage of the recent pullback to buy Suncor Energy under USD48.
Proven Reserves
A core holding in any energy-focused portfolio, Chevron Corp (NYSE: CVX) boasts a balance sheet that’s stronger than many sovereign ledgers, unparalleled geographic diversity of operations and exposure to a wide range of different projects. These strengths have enabled the company to increase its dividend for 23 consecutive years and approve yet another share buyback program, this time for up to $750 million.
Given the scope of Chevron’s operations, individual projects rarely alter the company’s production mix.
At this point, the company has exited seven countries and most markets on the US east coast. Chevron will further prune its downstream portfolio in 2011, focusing on marketing assets that aren’t supported by the company’s refining operations. Management also reported strong interest in its UK refining and marketing operations.
With the global recovery in full swing, oil demand continues to rise, especially in emerging markets. Our outlook calls for oil prices to remain above $100 per barrel and approach $120 at some point in 2011. Chevron apparently agrees with this forecast: The super major increased its 2011 capital budget to $26 billion, roughly 20 percent higher than in the prior year. This announcement reflects growing confidence in the sustainability of oil prices and reflects a trend we discussed at length in Here Comes the Spending.
Much of this money will flow to projects in the Asia-Pacific region, one of the company’s key growth areas.
In addition to the massive Gorgon LNG project in Australia that will serve India, China and other key Asian markets, management also plans to direct funds to exploration and production efforts in the Gulf of Thailand. The company noted that it made five additional natural gas discoveries in Western Australia, providing additional support for Gorgon and the Wheatstone LNG project, on which management expects a final investment decision in 2011. Management affirmed that the firm has commitments for 80 to 90 percent of the LNG volumes from each of these mega projects. The company also will likely sanction a natural gas project offshore Vietnam, a prospect that has services firms salivating.
Despite the company’s extensive natural gas projects in the Asia-Pacific region, management hasn’t made too big of a splash in North American shale gas plays–a wise move, given depressed US natural gas prices. Chevron’s pending acquisition of Atlas Energy (NSDQ: ATLS), a producer in the Marcellus Shale, pales in comparison to ExxonMobil Corp’s (NYSE: XOM) oft-criticized takeout of XTO Energy. Chevron did well to secure a low-cost, long-lived asset at a relatively cheap price.
In the coming years, we look forward to more news on its unconventional plays in Poland and Romania. The company should sink its first well in its Polish acreage in 2011; should these efforts produce appreciable amounts of natural gas, demand from Continental Europe–eager to reduce its reliance on Russian supplies–could prove lucrative. Nevertheless, this project has a ways to go before it approaches full-scale production, if it ever does.
Although Chevron’s production growth may slow in the intermediate term, the company’s sound balance sheet, capable management and attractive production profile make it a core holding. That being said, at this point in the cycle, we prefer smaller names that will be able to grow output meaningfully in the near term. Chevron Corp rates a buy under 105.
Enterprise Products Partners LP (NYSE: EPD) was a model of consistency in the first quarter, reporting a record $694 million in distributable cash flow (DCF), up nearly 20 percent from the $580 million it posted a year ago. Management hiked the company’s distribution for the 27th consecutive quarter–this time to $0.5975 per unit, a 5.3 percent increase from the year-ago level.
Enterprise generated enough DCF to cover its first-quarter payout by an impressive 1.4 times. The sale of some noncore assets bolstered DCF slightly, but even with $84 million in divestments backed out, the MLP covered its distribution by about 1.25 times.
Enterprise owns a vast pipeline, storage and processing network that spans more than 50,000 miles. Throughput was strong across the board, with the MLP reporting a 6 percent in natural gas volumes to a new quarterly record, NGL fractionation volumes up 16 percent and fee-based gas processing throughput up 38 percent year over year.
Although all Enterprise’s business segments performed well in the quarter, NGL pipelines and services was the star of the show. Gross operating margin, a measure of cash flow generated by the segment, jumped $67 million from 12 months ago. A jump in volume of NGLs processed, particularly in the Rockies and Texas’ Eagle Ford Shale, drove these gains.
During Enterprise’s conference call to discuss first-quarter results, management devoted considerable time in its prepared remarks and in the subsequent Q-and-A session highlighting the growth in demand for NGLs and the consequent need to build processing plants, fractionation facilities and pipelines. Rising demand from petrochemical plants continues to drive growth in this business. Chemicals companies make ethylene and propylene–the basic building blocks of most plastics–using either naphtha derived from crude oil or ethane and propane, two NGLs. With drilling activity in liquids-rich shale plays picking up, US production of NGLs has soared. This influx of NGLs has lowered the price of these key inputs relative to the Middle East and other markets.
Petrochemicals firms continue to expand their ability to produce ethylene and propylene from NGLs. In 2011 Dow Chemical (NYSE: DOW), Westlake Chemical Corp (NYSE: WLK), ConocoPhillips (NYSE: COP) and Chevron Corp have announced major expansions to their ethylene and propylene production plants, implying a sharp increase in demand for feedstock. Enterprise’s management estimates that ethane demand alone will increase by 200,000 to 300,000 barrels per day (bbl/day) by 2015.
Analysts often ask Enterprise’s management whether the industry is overbuilding NGL-related infrastructure. Although the firm expects demand growth to support this expansion, the company also enjoys a degree of protection against overbuilding; the MLP only begins these projects after negotiating long-term contracts with that guarantee pricing and cash flow.
For example, Enterprise’s 600,000 bbl/day gas processing plant in the Eagle Ford Shale is already fully subscribed under long-term contracts. Management is now in discussions with producers to determine whether throughput volume would support additional capacity.
The MLP is currently expanding its NGL fractionation facility at the Mont Belvieu hub, adding a fifth train slated for completion in December. The fifth train is already fully contracted under 10-year deals, and Enterprise has filed permits to add another train at the facility. Management emphasized that the firm won’t build a sixth train unless long-term contracts support another addition. At this point, demand for another train appears robust.
Rising demand for NGLs translate into higher throughput volumes at Enterprise’s facilities and a need for additional capacity near fast-growing unconventional gas fields. Nevertheless, management has gradually reduced its direct exposure to NGL prices in recent years.
Like most gas processors, Enterprise historically has performed some work on an equity basis, accepting a certain volume of NGLs as compensation for use of its facilities. But management has replaced these agreements with fee-based deals that are less sensitive to commodity prices and guarantee a minimum level of cash flow over the long term. Accordingly, in the most recent quarter, Enterprise processed fewer equity volumes of NGLs while increasing its fee-based business by 38 percent from a year ago.
Exports also contributed to the strength of the Enterprise’s NGL-related businesses. The firm is upgrading its propane export terminal on the Gulf Coast, adding another 10,000 barrels per hour of export capacity. Producers have booked the terminal’s capacity completely through the end of 2012. If Enterprise had completed a planned expansion to the facility in 2010, the company would have become the world’s second-largest exporter of propane, behind only the Saudi Arabia.
Major capital spending projects will drive Enterprise’s distribution growth over the next few years. The firm already has $5 billion worth of construction initiatives underway. All of these projects are backed by long-term contracts and commitments that guarantee cash flows. Management expects the MLP to spend $3.5 billion in 2011, with balanced expended in 2012.
The largest of these undertakings is a $1.6 billion extension to its Haynesville pipeline, a project that’s slated for completion in September 2011 and is currently on time and under budget. This pipeline will carry natural gas from Louisiana’s Haynesville Shale, primarily to industrial facilities along the Gulf Coast.
The firm also has 21 projects of varying sizes underway in the Eagle Ford Shale, one of the hottest shale fields in the US. The Eagle Ford produces a combination of oil, NGLs and natural gas, all of which require dedicated midstream infrastructure. Enterprise has leveraged its existing assets in the area to become the preeminent player in the Eagle Ford.
In addition to projects already under construction, Enterprise has announced a number of undertakings that will soon begin construction. This list includes a new pipeline it’s building in conjunction with Energy Transfer Partners LP (NYSE: ETP) that will carry 400,000 bbl/day of crude oil from Cushing, Okla. to the Gulf Coast.
This pipeline will meet a critical demand at Cushing, the physical delivery point for the West Texas Intermediate crude that underlies futures contracts traded on the New York Mercantile Exchange.
Rising US imports of Canadian oil, higher domestic output from shale oil fields and an uptick in ethanol production have prompted pipeline operators to add new lines or reverse the flow of existing lines to carry crude south to Cushing and other refinery centers. This shift has not only glutted storage facilities at Cushing, but the reversed pipelines have limited flows out of the hub.
When an influx of crude oil overwhelms refining capacity, stockpiles build, and the price of WTI declines. WTI has traded at historic lows relative to similar grades of crude oil delivered to the Gulf Coast. This logistical logjam can only be resolved by the construction of new pipelines to move crude oil from Cushing to the Gulf Coast, an area that’s home to about 30 percent of the nation’s refining capacity.
Enterprise is also eyeing projects in the Rockies and in west Texas and New Mexico. The Permian Basin of Texas is of the nation’s fastest growing oil-producing regions; horizontal drilling and fracturing techniques have enabled producers to boost output from these mature fields. Most of the region’s infrastructure is decades old and insufficient to accommodate rising output.
All told, Enterprise has no shortage potential growth projects. Management has noted that the firm would need to invest $1 to $1.5 billion annually in new projects to grow its distribution at the same rate as in recent years. But management plans to spend $3.5 billion in 2011 and $2.5 billion or more per annum over the next few years; Enterprise may grow its payout at an even faster rate.
Enterprise Products Partners has consistently grown its distribution and DCF over the years and should continue to benefit from rising NGL demand. The MLP is a play on many of the same trends as Eagle Rock Energy Partners but is a far more conservative bet because of the diversity of its business lines and track record of execution. Buy Enterprise Products Partners under 45.
Big integrated oil companies are traditionally considered the most defensive plays in the energy sector. Companies such as Proven Reserves Portfolio holding 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.
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.
When we added ExxonMobil to the Proven Reserves Portfolio in Energy Value Plays, uncertainty surrounding the Macondo oil spill in the Gulf of Mexico prompted many institutional investors to rotate capital out of the energy sector. In July 2010, integrated oil names traded at their lowest valuations since the panic-induced lows of 2008.
Investor sentiment toward ExxonMobil also suffered because of concerns that the energy giant overpaid for its blockbuster acquisition of natural gas-focused producer XTO Energy.
But rising oil prices and improving fundamentals in downstream (refining and marketing) business lines suggested that the integrated oil names would benefit from a cyclical recovery. Thus far, our investment thesis has panned out: Shares of ExxonMobil are up 0.6 percent since we added the stock to the model Portfolios on July 21, 2010.
Although the stock has pulled back from its high of $88.23 on Feb. 21, the stock’s valuation is no longer as compelling. Moreover, we continue to prefer fellow Proven Reserves Portfolio holding Chevron Corp for investors seeking growth and income. Not only does Chevron boast superior production growth and leverage to oil prices, but the company also has proved much more disciplined in its acquisitions–the acquisition of gas-focused Atlas Energy in November 2010 is a case in point.
Sell ExxonMobil Corp and reallocate the proceeds to our other Portfolio holdings.
Gushers
Oasis Petroleum (NYSE: OAS) is a fast-growing, pure play on the Bakken Shale in North Dakota and Montana.
It’s a lot easier to boost production and reserves of natural gas than it is to increase oil output. But Oasis Petroleum has been breaking that mold. The firm grew its first-quarter output by 146 percent from the prior year, producing 8,090 boepd in the first quarter of 2011. Better still, 95 percent of this production was crude oil.
Oasis Petroleum’s growth story is simple: The stock represents a play on continued growth in oil production and elevated oil prices. The direction of oil prices is the key near-term driver for the stock’s performance. The shares rallied in early 2011 when oil prices soared and topped out in late February and early March–first because of concerns about weather-related production delays and later because of a pullback in crude oil prices.
With oil prices capped by concerns about global growth in the short term, the stock could lose a bit more ground or trade sideways for a few more weeks. But I expect economic data to firm up in coming weeks, which should alleviate this concern. The timing of this improvement is difficult to call, but one thing is certain: The US economy isn’t at risk of slipping into recession.
Moreover, the global oil market remains supply-constrained because of strong demand growth in developing markets and the loss of about 1.5 million barrels per day of Libyan production capacity. OPEC’s recent failure to agree to an increase in production underpins this trend. Look for global oil and refined product inventories to decline sharply in the second half of 2011, propelling oil prices higher.
As for production growth, Oasis Petroleum will continue to follow its well-established playbook of drilling additional wells in its core 300,000-plus acres in the Bakken. Management has identified 1,303 potential drilling locations across its properties, and there’s significant upside to that estimate as it gains more drilling experience in its core plays.
The firm’s main areas of operation are the West Williston area near the border of North Dakota and Montana and the East Nesson and Sanish plays located to the east in North Dakota. West Williston accounts for almost 60 percent of the firm’s total reserves, 55 percent of production and 83 percent of planned capital spending in 2011. Six of Oasis Petroleum’s seven rigs operate in this area.
Oasis brought eight wells into production in the first three months of the year and was drilling three new wells toward the end of this period. As of March 31, the company had drilled 23 wells awaiting hydraulic fracturing (hydrofracking) services. Robust drilling activity in the Bakken has outstripped the supply of hydrofracking rigs and elevated prices for this critical service. These headwinds have also weighed on the stock in recent months.
Management has addressing some of these constraints by contracting with services firms for dedicated crews. Currently, the company has two dedicated fracturing crews working on wells; a third will begin work in July.
Meanwhile, the services industry continues to the US fleet of pressure pumping trucks and equipment; this additional capacity should begin to ease completion delays and cap service cost inflation into 2012.
The stock has also pulled back because of weather-related disruptions to the company’s drilling schedule. Management cited storms and flooding as one of the reasons the firm’s second-quarter production would likely fall short of its output in the first three months of the year. The summer should provide Oasis Petroleum with an opportunity to play catch up, but several analysts have downgraded their estimates of the company’s 2011 production forecast to less than the 11,000 boepd that management has projected.
Even with these challenges, Oasis Petroleum’s 2011 output should be double 2010 levels. Moreover, weather-related disruptions and delays related to a shortage of hydrofracking capacity are temporary headwinds: The quality of the firm’s reserves is undiminished. As these challenges subside, the firm should be able to grow its annual output at a rate of 100 percent-plus over the next few years. That the stock rallied after management reduced its production guidance suggests that much of the bad news is already priced into the shares.
Management expects to complete about 69 total wells and 47 net wells in 2011–that is, some of the wells are 100 percent owned by Oasis, while others are only partially owned by the firm. Management has budgeted $402 million in capital spending on wells it operates and $39 million for the non-operated wells in which it has a stake.
There is significant upside potential to this capital spending program, and the company plans to update drilling activity guidance when it reports second quarter earnings in August. Already management has hinted that it’s working to secure two additional rigs for the back half of 2011. This could be a key catalyst for the stock, as any increase in activity would signal faster-than-expected production growth potential and easing capacity constraints.
Investors should be extremely careful when valuing Oasis Petroleum and other exploration and production firms (E&P) because traditional earnings metrics can be misleading. For example, in the first quarter, Oasis reported a loss of more than $6.8 million, largely the result of mark-to-market adjustments to the company’s hedging positions.
Like many E&P firms, Oasis Petroleum uses futures, swaps and options to lock in prices for a portion of its production and reduce exposure to volatile commodity prices. In each quarter, the company must mark the value of all of these instruments to market whether they expired in the quarter or expire years in the future. When oil and gas prices rise, these firms will report large losses on their hedges. But E&Ps don’t have to pay out cash to maintain their hedges when these instruments lose value. In the first quarter, mark-to-market adjustments reduced Oasis Petroleum’s earnings by over $31 million; without these adjustments, the company generated sizeable real earnings.
I tend to focus on operating cash flow and adjusted earnings before interest, taxation, depreciation and amortization (EBITDA) to get around these distortions. On that basis, the stock trades at a slight discount to its peer group despite the firm’s superior growth potential. In fact, the company’s first-quarter operating cash flow soared more than 200 percent from year-ago levels. The company has also already funded all of its planned 2011 capital spending and some of its 2012 budget.
With real earnings power of as high as $2.50 per share in 2012, the stock could hit $40 later this year. Buy Oasis Petroleum under 37.
An early entrant in the Haynesville Shale of Louisiana and the Eagle Ford Shale in south Texas, Petrohawk Energy (NYSE: HK) has amassed high-quality acreage positions in both plays. But the company’s astute management team is an equally important asset to shareholders.
For many gas-focused exploration and production firms, 2010-11 marks an important transitional period that will separate the long-term winners from the losers. With an oversupply of natural gas continuing to depress prices, Petrohawk Energy has focused on shoring up its balance sheet by divesting nonessential assets, increasing the liquids content in its production mix and securing leaseholds in the sweet spots of its core plays.
To this end, the company sold its acreage and midstream assets in Arkansas’ Fayetteville Shale to XTO Energy, a subsidiary of ExxonMobil Corp (NYSE: XOM), for $650 million. Management indicated that the proceeds from this transaction will be plowed into the company’s 2011 capital budget, with the goal of more than doubling its NGL, condensate and oil output to 12 percent of total production. Management estimates that 30 percent of the company’s acreage is prospective for NGLs, condensate or crude oil.
If the company meets its 2011 production guidance, liquids would account for 27 percent of revenue, a substantial uptick from 2010.
This shift will begin in the back half of 2011, when management expects the company to have secured all of its core leaseholds in the Haynesville by production. Not only will that enable Petrohawk Energy to reduce drilling activity in this prolific dry-gas field, but management will also be able to allocate more capital to its operations in the liquids-rich Eagle Ford Shale. In the final six months of 2011, the company will reduce its rig count in the Haynesville to seven from 16. In 2010 the firm sank 351 wells in the Haynesville Shale, 101 of which it operated; in 2011 Petrohawk Energy expects to drill 88 wells in the play–57 in the first half of the year and 31 in the back half.
As part of its strategic plan, Petrohawk Energy will let the leases on 135,000 acres of its noncore Haynesville territory expire, leaving it with about 225,000 acres, of which it operates about 75 percent.
Since Petrohawk Energy began drilling in the Haynesville, the company has focused on honing its drilling techniques to reduce costs and improve estimated ultimately recoverable (EUR) natural gas. Its engineers discovered that restricting flow rates both reduces production costs and increases EUR by an average of 2.5 billion cubic feet (Bcf). In 2012-13, after Petrohawk Energy secures its leasehold in the Haynesville, the company has the option to begin full-scale production. Using multi-well pads would reduce expenses substantially–management pegs costs in the Haynesville at $10.6 million per well–reducing the down time between wells and the cost of relocating equipment between drilling sites.
Management also indicated that Petrohawk Energy would likely sell its 50 percent stake in the KinderHawk, one of the largest gathering and processing systems in the Haynesville, or spin the operation off as a master limited partnership.
Despite these potential cost improvements, the company’s Haynesville acreage represents a long-term opportunity.
In the near term, Petrohawk Energy will focus on ramping up its operations in the Eagle Ford Shale, a play the company discovered in 2008. Over the past three years, the company has amassed about 357,000 commercially producible acres in the Eagle Ford. Its leasehold is located in three distinct areas: Hawkville, Black Hawk and Red Hawk.
In 2010 the company drilled 36 operated wells and five non-operated wells in Hawkville, a 225,000-acre play that comprises two distinct regions: one which contains dry gas and one which includes natural gas and condensate. Well costs in the region average $7.5 million per well. The five rigs that will operate in the region in 2011 will likely focus on the condensate-rich window. As part of an exclusive partnership with Wildcatters Portfolio holding Schlumberger, Petrohawk Energy began testing the services company’s HiWAY flow-channel hydraulic fracturing technique last fall. Early results suggest that this approach, which improves conductivity within in the reservoir rock, will elevate EURs.
The approximately 73,600-acre Black Hawk field, rich in NGLs and condensate, offers Petrohawk Energy the best returns in the current pricing environment. The company drilled 29 Black Hawk wells in 2010, generating an average of 385 barrels of condensate per million cubic feet (Mcf) of gas and 100 barrels of natural gas liquids per Mcf of gas. Management plans to sink 89 wells in 2011 in an effort to grow its liquids output.
Red Hawk is an oil-prospective area where Petrohawk Energy has sunk five wells, two of which were awaiting completion as of March 30. One of these wells didn’t produce favorable results, but the Mustang Ranch “C” #1H has flowed crude oil at a rate that suggests EUR of 200,000 barrels. The company will drill five additional wells in this area at an average cost of $5 million per well.
Petrohawk Energy balances its prolific dry-gas assets in the sweet spot of the Haynesville Shale with growing liquids production from the Eagle Ford Shale. With a sound balance sheet and a plan to generate positive cash flow by 2013, the company is headed in the right direction.
But with US natural gas prices likely to remain weak for some time, Petrohawk Energy Corp continues to rate a hold.
Valero Energy Corp (NYSE: VLO), the world’s largest independent refiner, currently operates 14 petroleum refineries–seven on the US Gulf Coast, three in the Midcontinent region, two on the West Coast, one in Canada and one in Aruba–capable of processing a total of 2.6 million barrels per day. The company’s throughput capacity will increase by a further 270,000 barrels per day (220,000 of which are crude oil) once its acquisition of Chevron’s UK Pembroke Refinery closes.
Valero’s refining operations accounted for almost 85 percent of its 2010 revenue, while the firm’s retail operations in the Americas–about 5,800 locations in the US, Aruba and Canada– represented about 11.3 percent of sales last year. The firm’s ethanol production plants in the US Corn Belt generated about 3.7 percent of 2010 revenue.
On Feb. 27, 2010, we added Valero Energy to the Gushers Portfolio as a shorter-term investment that stood to benefit from improving fundamentals. (See A New Dark Age for Refiners.) The stock has rallied 41.3 percent since it joined the model Portfolios. Although weakness in US equities has eroded our gains, cyclical trends should enable the stock to retest its 2011 high.
Broadly speaking, the refining industry continues to benefit from rising global demand for gasoline, diesel and other refined products as consumption recovers in the developed world and emerging-market demand expands at a rapid rate.
On the supply side, the overcapacity that has plagued refinery operators in the US and Europe continues to ease.
Over the past few years, integrated oil companies have sought to rationalize their downstream operations, divesting less profitable refineries in the US in favor of facilities in the Middle East and Asian emerging markets, two regions that offer superior margins and growth prospects.
Meanwhile, independent US refiners have also moved to reduce capacity, selling or closing smaller (and therefore less-efficient) plants on the East Coast–a highly competitive region that lacks access to cheaper domestically produced crude oil. The majority of oil refined at East Coast facilities arrives via tanker from Nigeria, the North Sea and other international locations.
Valero Energy estimates that these moves reduced global spare refining capacity to 5.9 million barrels per day at the end of 2010 from about 7 million barrels per day at the end of 2009. The company also got in on the act, selling its Delaware City and Paulsboro, NJ refineries in 2010.
In addition to these broad supply and demand factors, Valero Energy has benefited from a robust cost-cutting program that has lowered operating expenses from $4.41 per barrel of refined in 2008 products to $3.69 per barrel in the first quarter of 2011.
But the biggest near-term upside catalyst for Valero Energy remains the flexibility of its refineries: About 80 percent of the company’s refinery capacity can process feedstock that trades at a discount to light-sweet crude. With Mexican oil output stabilizing and rising production of heavy oil from Colombia, the refiner should reap the rewards of attractive spreads on heavy-sour and medium-sour grades of crude relative to light-sweet, waterborne crude oils.
Exporting diesel from the company’s core operations on the Gulf Coast has also generated fat margins in recent months.
Meanwhile, the company’s three facilities in the Midcontinent region stand to benefit from the widening spread between the price of West Texas Intermediate (WTI) crude (a popular US benchmark) and Brent crude oil (a European benchmark that better reflects trends in global oil demand).
WTI generally commands a slight premium to Brent crude oil, but that relationship has reversed over the past 12 months. Local supply conditions at the physical delivery point in Cushing, Okla. are the culprit: Rising US imports of Canadian oil, higher domestic output from shale oil fields and an uptick in ethanol production have prompted pipeline operators to add new lines or reverse the flow of existing lines to carry crude south to Cushing and other refinery centers.
This shift has not only glutted storage facilities at Cushing, but the reverse pipeline have limited flows out of the hub. When an influx of crude oil overwhelms refining capacity, stockpiles build, and the price of WTI declines. This logistical logjam can only be resolved by the construction of new pipelines to move crude oil from Cushing to the Gulf Coast, an area that’s home to about 30 percent of the nation’s refining capacity. This tailwind should be in play for some time.
With some of its Gulf Coast and Midcontinent refineries down for maintenance in the first quarter, the second and third quarters should feature higher throughput volumes. Nevertheless, Valero Energy Corp continues to rate a hold at current levels.
Fresh Money Buys
The stocks recommended in the three model Portfolios represent my favorite picks. The three Portfolios are designed to target different levels of risk: Proven Reserves is the most conservative; the Wildcatters names entail a bit more volatility; and Gushers are the riskier plays but have the most potential upside.
I realize that this long list of stocks can be confusing; subscribers often ask what they should buy now or where they should start. To answer that question, I’ve compiled a list of 18 Fresh Money Buys that includes 16 stocks and two hedges.
I’ve classified each recommendation by risk level–high, low or moderate. Conservative investors should focus the majority of their assets in low- and moderate-risk plays, while aggressive investors should layer in exposure to my riskier and higher-potential plays. Hedges are appropriate for investors looking to offset exposure to energy stocks.
Also note that stocks that exceed my buy target for more than two consecutive issues will either be removed from the list or the buy target will be increased.
Source: The Energy Strategist
Join Me in the City by the Bay
I am thrilled to be returning to San Francisco this year and invite you to join me at The MoneyShow, August 10-12, 2011, at the San Francisco Marriott Marquis Hotel. Be there as recommendations and advice are revealed for how to best position your portfolio for profit—in 2011 and beyond. As this new era of investing unfolds, smart investors know it’s imperative to stay informed and educated. The MoneyShow is your one-stop resource for the most comprehensive education, efficient research, and valuable advice. Don’t miss out…register FREE today and be sure to mention Priority code 022447!
Despite the negative headlines in the financial press, the S&P 500 slipped only modestly in May and early June. But over the past two weeks the broader market has sold off even on slow news days. Individual names have also pulled back after announcing positive developments. Nevertheless, the S&P 500 has pulled back only 5.6 percent since May 1, compared to a 9.6 percent decline over the same period last summer. Investors should expect the market to trade lower or sideways for a bit longer.
Regardless of its duration, this summer swoon remains an excellent buying opportunity.
Although my holiday in Santorini, Greece (for pictures, check out my Twitter account) hasn’t been interrupted by the recent protests in a handful of cities, I did catch a TV broadcast Prime Minister George Papandreou’s speech to parliament before the confidence vote took place. My command of the local language isn’t the best, but I could tell that Papandreou did not sound as though he was ready to give up the fight for his proposed austerity measures.
After the prime minister won the confidence vote, odds favor the passage of additional budget cuts and further aid from the EU and the International Monetary Fund, both of which should stave off the threat of default.
Still, Greece will face significant hurdles in coming years, from passing a fourth round of austerity measures to gradually restructuring the national economy. But don’t let the sensationalist stories in the US media dissuade you from visiting the country this summer–the nation hasn’t descended into utter chaos. In fact, all of my flights into and out of Athens were more punctual than my flights from Washington, DC. At this point, the protests have been confined to the city center.
The purported deaths of the EU and the euro are also greatly exaggerated. If the EU were on the verge of collapse, would the currency still trade for USD1.44?
Last summer, we repeatedly told readers that the challenges in peripheral economies such as Greece and Ireland wouldn’t send the rest of the EU spiraling into recession. If Greece were to default on its sovereign debt, the market worried that global credit markets might freeze once again.
Although the situation in Greece bears watching, Italy and its USD2.11 trillion economy pose a much larger risk. Despite Italy’s high debt-to-GDP ratio, its government is in much better fiscal health than Greece. The Italian government has reduced its budget, but doesn’t require the magnitude of cutbacks that its Mediterranean counterpart must endure to get its fiscal house in order. Italy’s economy hasn’t slipped into recession. Moreover, Italy’s budget deficit this year will be among the lowest in the EU.
The second act of the Greece’s sovereign debt drama has raised the cost of credit default swaps (CDS) for Italian government bonds. But at 175 basis points, five-year CDS on Italy’s sovereign debt trade remain well short of the levels that prevailed during the Irish debt crisis.
This contagion has yet to affect the US credit market. For example, the TED spread–the difference between the London Interbank offer rate and the yield on short-term Treasury bills–stands at just 22 basis points, less than half its 2010 high. US corporations continue to sell bonds, paying interest rates that represent near record-low spreads over Treasuries.
Finally, recent data suggests that the US economy may be emerging from its recent soft patch.
Source: Bloomberg
This Citigroup US Economic Surprise Index compares the consensus estimate for key economic data to the actual figures. Negative numbers indicate that economic data has consistently come in below expectations.
As you can see, data came in well under consensus outlooks starting in April, when the index plummeted to a multiyear low. But last week US economic data–including jobless claims and retail sales–largely beat the consensus expectations. Although it’s too early to claim definitively that the US economy has turned the corner, this could be the first sign that supply-chain disruption stemming from the earthquake in Japan’s Tohoku region have begun to abate. Lower oil prices should also provide some relief to US consumers.
Regardless of whether this improvement proves durable, the data suggests that the US economy isn’t at risk of slipping into a recession.
The latest summer swoon should follow the pattern established in 2010. Expect concerns about the EU sovereign debt crisis and a US economic slowdown to fade as the summer progresses. Meanwhile, the ongoing correction in the stock market offers investors a great opportunity to buy our favorite energy stocks at attractive prices.
Although macro concerns continue to dominate the tape, investors should never lose site of the outlook for their holdings. In this issue, we revisit our investment thesis for 14 of our model Portfolio holdings and review each name’s growth prospects. This exercise should bring new readers up to speed with our picks and provide longtime readers with piece of mind.
In This Issue
The Stories
Macro developments may be driving the stock market, but it’s important not to lose sight of company- and industry-specific fundamentals. We revisit our investment theses for 14 holdings in the model Portfolios. See Wildcatters, Proven Reserves and Gushers.
Want to know what to buy now? Check out the Fresh Money Buys list. See Fresh Money Buys.
The Stocks
BG Group (LSE: BG/, OTC: BRGYY)–Buy < GBp1,650 or USD133
Cameron International Corp (NYSE: CAM)–Buy < 62
Core Laboratories (NYSE: CLB)–Buy < 105
Dresser Rand Group (NYSE: DRC)–Buy < 55
Eagle Rock Energy Partners LP (NSDQ: EROC)–Buy < 12
Linn Energy LLC (NSDQ: LIBE)–Buy < 40
Peabody Energy Corp (NYSE: BTU)–Buy < 72.59
Suncor Energy (TSX: SU, NYSE: SU)–Buy < USD48
Chevron Corp (NYSE: CVX)–Buy < 105
Enterprise Products Partners LP (NYSE: EPD)–Buy < 45
ExxonMobil Corp (NYSE: XOM)–SELL
Oasis Petroleum (NYSE: OAS)–Buy < 37
Petrohawk Energy (NYSE: HK)–Hold
Valero Energy Corp (NYSE: VLO)–Hold
Wildcatters
BG Group (LSE: BG/, OTC: BRGYY) operates three business segments–liquefied natural gas (LNG), exploration and production (E&P) and transmission and distribution (T&D)–each of which offers exposure to a number of near- and long-term catalysts.
The firm’s LNG operations, which include liquefaction and re-gasification assets as well as the purchase, shipment, marketing and sale of LNG, accounted for roughly 35 percent of the company’s 2010 revenue. BG’s LNG operations and assets span the globe and, in many instances, complement its E&P efforts.
How do these disparate assets work within BG’s business model? BG’s LNG trading and shipping divisions work together to market, sell and deliver LNG volumes to customers worldwide on both a short- and long-term basis. In addition to marketing its own contracted LNG, the firm also buys volumes on regional spot markets and resells this gas to take advantage of regional pricing discrepancies. To support these trading activities, the company’s shipping arm boasts a fleet of owned and contracted ships.
Over the long term, BG’s extensive global operations should enable the firm to benefit from a global LNG market where demand growth outstrips constrained supply. In 2010 nations such as Spain, Belgium and the UK absorbed much of the LNG supply overhang that persisted after the global recession weakened demand and the ongoing shale gas revolution transformed the US market into an outlet of last resort.
LNG figures to become an increasingly important part of the Continent’s energy mix. Supply constraints, the planned decommissioning of nuclear reactors in Germany and a desire to limit reliance on Russian natural gas should prompt EU nations to build out the necessary cross-border pipeline and support infrastructure.
But the Asia-Pacific region–where long-term, oil-indexed contracts are the norm–represents the most exciting growth opportunity for BG. Management underscored this point during its Feb. 8 conference call to discuss the company’s 2010 results and outlook, noting that the use of oil for heating purposes provides ample opportunity for fuel substitution. High economic growth in Asian emerging markets should continue to drive robust demand among industrial, commercial and residential consumer segments.
Natural gas currently accounts for only 4 percent of China’s energy mix, but BG estimates that an increase of 1 percent in gas penetration adds 25 billion cubic meters per year to Chinese gas demand. That’s equivalent to the total output from four liquefaction trains at BG’s massive Queensland Curtis LNG (QCLNG) Project in Australia.
Management also noted that if gas penetration in China were to approach the levels in India–still low by global standards–Chinese gas demand would increase by roughly 150 billion cubic meters per year, or about 1.5 times Qatar’s LNG production capacity. For those wondering about this seemingly obscure comparison, Qatar is the world’s leading producer of LNG.
Based on management’s forecast for Chinese LNG demand growth and the likelihood of new markets coming online, global demand will likely eclipse the current consensus projection of 350 mtpa in 2020. At present, only 280 mtpa of liquefaction facilities are in operation or have been sanctioned for construction. With its low-cost supply base and global operations, BG is well-positioned to benefit over the long term from tightening in international LNG markets.
For one, management forecasts that once QCLNG comes online, 75 percent of the firm’s LNG sales will be based on oil prices.
BG’s E&P division includes operations in the UK and Norwegian portions of the North Sea as well as stakes in emerging plays offshore Thailand, India, China and Tanzania. But the crown jewel of the company’s E&P operations are its interests in six blocks offshore Brazil, in the highly prospective Santos Basin.
Expanding production, coupled with resource upgrades and new discoveries offshore Brazil, should provide plenty of catalysts for BG’s shares over the next few years. In the near term, drilling activity offshore China and Tanzania could provide further upside.
BG’s transmission and distribution operations are concentrated in Brazil and India, two emerging markets where demand for natural gas-fired power plants will continue to grow as their economies expand.
The stock pulled back after the company posted first-quarter earnings that fell short of analysts’ consensus estimate and volume growth also disappointed. Nevertheless, the company’s mid- to long-term growth story remains intact. Buy BG Group under GBp1,650 on the London Stock Exchange or USD133 in the over-the-counter market.
We added Cameron International Corp (NYSE: CAM) to the Wildcatters Portfolio in an Oct. 13, 2010 Flash Alert, citing the stock’s attractive valuation and the company’s exposure to an uptick in offshore and deepwater drilling activity. Thus far, our investment thesis has yet to pan out: The stock is up only 7.5 percent over our holding period, underperforming the S&P 500 by almost 3.2 percent and the Philadelphia Oil Services Index by 13.1 percent.
First-quarter earnings per share were 17 percent shy of Wall Street’s consensus estimate, sapping the stock’s upward momentum and raising concerns about the timing of a turnaround in the company’s long-cycle business lines. Some investors worry that the company could suffer a lull in order bookings if sales of its short-cycle products begin to ease and demand for its long-cycle products doesn’t kick in immediately.
Despite these short-term concerns, Cameron International’s diverse business footprint and exposure to key secular growth trends in offshore and deepwater drilling make the stock an excellent pick for investors seeking long-term growth. Six of Cameron International’s 11 business lines offer exposure to deepwater the space, and the company holds the No. 1 or No. 2 market share in the majority of its product categories. Meanwhile, the firm usually generates about two-thirds of its revenue outside North America.
Cameron International operates three business segments: drilling and production systems (60.6 percent of 2010 revenue), valves and measurement (20.8 percent), and compression systems (18.6 percent).
Investors tend to focus on the drilling and production systems segment, which includes drilling systems, offshore systems and surface systems. Although the company’s surface (onshore) sales benefited from robust demand in US shale plays, the offshore segment is the star of the show because of the potential for huge project awards.
Management has indicated that it expects major project awards over the next six to 18 months offshore Brazil, West Africa, Australia and Asia-Pacific, but acknowledged many project awards have been delayed. This could be a boon for sales of the company’s subsea equipment, which include trees, wellheads and controls among other items.
The Macondo oil spill in the Gulf of Mexico ironically gifted Cameron International with a new growth opportunity, though the failure of blowout preventer (BOP) that it manufactured was a big part of the disaster.
A BOP is a large, heavy device that’s installed directly on the seafloor above a deepwater well during the drilling process and removed after the well is completed. The BOP is an emergency mechanism that, once activated, seals off a well and prevents hydrocarbons from escaping by ramming a rod with a rubber seal into the well. These devices include several backup mechanisms.
Cameron International’s BOPs boast an installed base of roughly 50 percent on offshore rigs; new rules requiring original equipment manufacturers to service this equipment on a regular basis should bolster the company’s aftermarket revenue. Nevertheless, some analysts have noted that competitor National Oilwell Varco’s (NYSE: NOV) BOPs appear to be winning share in the new sales market.
An uptick in orders for floating production, storage and offloading (FPSO) vessel such as those used offshore Brazil would be a boon for the company, particularly the firm’s valves and measurement business. Much of these orders would come from projects offshore Brazil and West Africa. Cameron International’s Cynara membrane technology, which it added to its portfolio when it acquired NATCO in 2009, could help solve the carbon dioxide separation challenges Petrobras (NYSE: PBR) has encountered in its pre-salt fields.
With $1.8 billion in cash on its balance sheet and an undrawn credit facility, Cameron International can afford to invest in future growth. The firm already boasts the only facility in the African nation of Angola that can design, assemble and test subsea equipment, and plans to invest considerable amounts to boost its presence in Brazil.
Cameron International rates a buy up to 62 for growth-oriented investors with a longer time horizon.
Netherlands-based Core Laboratories (NYSE: CLB) provides a range of services and solutions that enable oil and natural gas producers to maximize a energy output throughout a field’s life cycle. The company operates three business segments:
- Reservoir Description (about 52 percent of first-quarter revenue) conducts complex analyses of the porosity and permeability reservoir rocks, as well as the quantity and quality of fluids therein. This information is essential to allocating capital and calculating returns, and enables producers to develop an informed, efficient and cost-effective plan for extracting hydrocarbons from a recently discovered field.
- Production Enhancement (almost 40 percent of first-quarter revenue) analyzes producing fields to determine the best way to enhance production, either through hydraulic fracturing–as in the Bakken and other onshore US oil plays–or flooding with water, miscible gas or carbon dioxide. This division also produces popular perforating technologies that increase the effectiveness of hydraulic fracturing.
- Reservoir Management (about 8 percent of first-quarter revenue) involves reservoir management and monitoring throughout the course of an oil field’s life. These multi-client surveys and studies take place in both shale oil plays and in deepwater fields.
In the first quarter, spending in international markets failed to pick up measurably, limiting year-over-year revenue growth in the company’s reservoir description business to 3 percent. Nevertheless, management affirmed that it expects spending on exploration and production to increase at least 10 percent in international markets.
During Core Labs’ conference call to discuss first-quarter earnings, CEO David Demshur cited this slow turnaround and unrest in the Middle East and North Africa as the reasons for the company’s conservative guidance for the second quarter.
Meanwhile, the company’s production enhancement division grew revenue by 19 percent from a year ago, despite inclement winter weather that shut down drilling activity in certain US shale oil plays. However, these delays did weigh on margins, which declined by 200 basis points to 28 percent.
The unit’s results were bolstered by a project to monitor the water and gas flooding of a field offshore West Africa. Strong North American demand for the company’s HTD Blast firing system, which increased its market share to 19 percent from 17 percent in the fourth quarter, also boosted revenue. This technology, which increases the effectiveness of hydraulic fracturing, has proved popular in the Bakken and other shale oil fields.
Finally, the firm’s reservoir management division generated 10 percent more revenue in the first quarter than it did a year ago, with margins improving 300 basis points to 39 percent. In the first three months of the year, the firm kicked off a consortium study of the Avalon oil play, which encompasses parts of New Mexico and West Texas. Thirty-seven companies have now signed on to participate in the company’s Eagle Ford study, data from which will enable producers to maximize ultimate recovery rates.
Although a broader pullback in oil services stocks and Core Labs’ conservative guidance for the second quarter have weighed on the stock, our investment thesis remains intact.
The end of easy oil has forced producers into the deepwater and other expensive-to-produce plays, increasing demand for Core Labs’ reservoir description services. Given the service intensity and expenses required in these fields, producers are eager to pony up for the company’s reservoir description services, which can expedite the exploration and development process and limit costs during this phase. At the same time, the company’s production enhancement business should benefit from efforts to maximize output from producing wells.
These upside drivers could make Core Labs an attractive takeover target for a larger services firm. Buy Core Laboratories up to 105.
Dresser Rand Group (NYSE: DRC) is among the largest global suppliers of turbines, compressors and other high-speed rotating equipment primarily to the oil, natural gas and petrochemical industries. Oil- and gas-related markets accounted for roughly 83 percent of the firm’s 2010 sales, but the company’s products are also used by the US Navy and the paper, steel, sugar and power generation industries.
The company’s products are key components in all three segments of the energy patch: upstream (exploration and production), midstream (pipelines and storage facilities) and downstream (refining and marketing). For example, oil production ceases if a compressor stops pumping gas into a well, while a failed compressor will prevent a pipeline from transporting natural gas.
Dresser Rand divides its business into two segments, each of which accounted for about half the firm’s annual revenue in 2010: new-unit sales and aftermarket services.
New-unit sales should continue to benefit from a cyclical recovery in spending on exploration and production and investment in oil- and gas-related infrastructure.
In the upstream category, the company’s biggest growth opportunities are in offshore and deepwater markets, particularly in FPSO vessels and liquefied natural gas (LNG)-related infrastructure.
For example, Dresser Rand already delivered the world’s highest-density compressor to Japanese shipbuilder Modec (Tokyo: 6269, OTC: MDIKF) as part of an FPSO ordered by Brazilian national oil company Petrobras. A replacement for expensive carbon-dioxide pumps, this technology occupies less space on the vessel and reduce costs by USD5 to USD10 billion.
Once perfected and modified for subsea applications–to maximize output from mature fields, producers often put the compressor on the seafloor–this innovation could enable Dresser Rand to grow its share of the rapidly growing offshore drilling market.
Meanwhile, the company has also established a strategic alliance with Samsung Heavy Industries (Seoul: 010140) to provide compressors for LNG import and export projects as well as floating LNG rigs–imagine a mobile, offshore liquefaction facility. This agreement should enable the company to place its product on the many LNG-related projects on which Samsung Heavy Industries works.
Better still, once these new units are in place, the company enjoys a reliable revenue stream (and higher margins) from aftermarket service and parts. At present, management estimates the installed base of its compressors at almost 100,000 units–four times the amount of its closest competitor. The more units the company sells, the more follow-up revenue its aftermarket business will generate.
In the midstream space, Dresser Rand stands to benefit from rising demand for pipelines, processing plants and other energy infrastructure in both developed and emerging markets. In the US, for example, the rapid development of shale oil and gas fields necessitates massive investment in supporting infrastructure, much of which will require compressors.
In the downstream space, management estimates that the company has the opportunity to sell $50 million worth of equipment for every 200,000 barrels per day of refining capacity added in emerging markets.
Over the past decade, management has reoriented Dresser Rand’s business strategy to better reflect the growing importance of national oil companies and rising demand for energy infrastructure in emerging markets such as offshore Brazil and West Africa. The company continues to invest in expanding the global reach of its service centers, particularly in Brazil and the Middle East. Because of these efforts, Europe and North American accounted for only 56 percent of the firm’s 2010 revenue.
In recent years, the company has courted business in the environment services sphere, including waste-to-energy solutions, wind energy, energy storage and clean coal. Management has assured investors that many of its opportunities in this space don’t depend on government subsidies.
With exposure to attractive growth markets and an order backlog that suggests 2012 could be a record year for sales, Dresser Rand rates a buy up to 55.
Eagle Rock Energy Partners LP (NSDQ: EROC) is a master limited partnership (MLP) that operates two businesses: gathering and processing (G&P) and upstream.
Upstream operations involve the production of crude oil, natural gas and natural gas liquids (NGL) from the partnership’s properties in Texas and southern Alabama. In 2010 Eagle Rock Energy produced slightly more than 5,000 barrels of oil equivalent per day (boepd) from 273 operated wells and 137 non-operated wells in which the MLP owns an interest.
The G&P business consists of 5,500 miles of gathering pipelines in the Texas Panhandle, east Texas and Louisiana, south Texas, the Gulf of Mexico and west Texas. These small-diameter pipelines connect individual wells to processing facilities and, ultimately, the US interstate pipeline network. The firm also owns 19 gas processing plants that separate NGLs such as propane and ethane from raw natural gas; these plants are typically associated with Eagle Rock Energy’s gathering systems. In 2010 the firm gathered an average of 500 million cubic feet of gas equivalent per day and processed just over 300 million cubic feet per day.
Having passed one of the most difficult stress tests in its history, Eagle Rock Energy looks poised for significant growth over the next 18 months. In late 2008 and early 2009, plummeting natural gas prices prompted producers to rein in drilling activity, reducing throughput on Eagle Rock’s gathering systems. Meanwhile, the collapse in commodity prices also lowered profit margins in the firm’s processing business, which earns additional fees based on the sale price of NGLs and natural gas.
These trying times forced management to slash the firm’s quarterly distribution to the bone.
Although natural gas prices remain depressed, drilling activity continues apace in the nation’s liquids-rich shale plays; throughput volumes on Eagle Rock Energy’s gathering systems has recovered fully. Meanwhile, higher NGL prices have bolstered profit margins in the company’s processing business.
But management has also taken key steps to reduce its G&P segment’s exposure to commodity prices. The firm also undertook a restructuring effort that lowered its debt burden and eliminated the need to pay incentive distribution fees to the partnership’s general partner.
In light of these changes, we upgraded Eagle Rock Energy to a buy in a Flash Alert issued on June 10, 2010. Since then, the stock has generated a total return of 143 percent.
Eagle Rock Energy’s now has a solid platform for growth in both of its business lines. The firm’s G&P assets serve NGL-rich fields, which helps offset weak natural gas prices.
As the price of a barrel of NGLs tends to follow crude oil more closely than gas, producers with significant exposure to liquids-rich gas plays enjoy strong drilling economics. Several US-based petrochemical producers also have announced plans to build or expand their capacity to produce ethylene and propylene–the building blocks of many plastics–from NGLs. Meanwhile, US NGL exports have also hit record levels.
All of this adds up to higher throughput and profit margins for Eagle Rock Energy’s G&P assets.
The firm’s Texas Panhandle system serves the Granite Wash, a field that several producers are targeting using a combination of horizontal drilling and hydraulic fracturing techniques. The field produces extremely wet natural gas volumes–gas that’s high in NGL content–along with significant volumes of high-value condensate and some crude oil.
Given that liquids-rich mix, about 66 rigs operated in the play as of the end of the first quarter. Volumes of NGLs processed and recovered declined because of unusually cold winter weather in the first quarter of 2011, but that dip will give way to strong growth later in the year.
Another promising region for Eagle Rock Energy’s midstream business is its East Texas system, which serves the liquids-rich Austin Chalk. In the first three months of 2011, volumes gathered in the region increased by 3 percent from the previous quarter, while NGL and condensate volumes jumped 6 percent over this period.
The main growth driver in Eagle Rock Energy’s upstream business will be the $530 million acquisition of the Crow Creek properties in Oklahoma, Texas and Arkansas. This deal illustrates how far Eagle Rock has come over the past year and a half: A company once considered near bankruptcy closed a major acquisition and raised $300 million in capital via a bond offering that currently yields 8.5 percent.
When the transaction closed in May 2011, Eagle Rock Energy’s oil and gas reserves jumped by 200 percent from the end of 2010. The deal has also decreased Eagle’s exposure to natural gas production and increased the partnership’s focus on NGLs and condensate output.
Management has also stepped up its hedging program to lock in favorable market prices for oil, NGLs and natural gas. The partnership has hedged 80 percent of its 2011 natural gas production and 69 percent of its liquids output. In 2012 about 70 percent of the firm’s natural gas and liquids production has been hedged.
Based on the recent acquisitions and growth in midstream volumes, Eagle Rock Energy expects to boost its distribution to an annualized rate of $0.75 by the end of the second quarter and $1 per unit by the end of 2012–a substantial increase from the current annualized payout of $0.60.
Improving fundamentals and a growing distribution make Eagle Rock Energy Partners LP a buy under 12.
Linn Energy LLC (NSDQ: LINE) is a limited liability company (LLC), an organizational structure similar to an MLP, with producing properties in six distinct areas: the Permian Basin of West Texas, the Los Angeles basin of Southern California, the Bakken Shale of North Dakota, the Permian Basin of West Texas, the Midcontinent of Northern Texas and Oklahoma and the Antrim Shale of Michigan.
The Midcontinent and Permian are the two most important regions, accounting for a bit over 80 percent of the firm’s total reserves. Oil and NGLs account for about 55 percent of total reserves; natural gas accounts for the remaining 45 percent.
Linn Energy’s business model is simple: acquire mature oil and gas-producing assets and hedge the majority of their 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; recently, the partnership issued 10-year bonds offering a yield of less than 7 percent. That’s an impressive rate, especially when you consider Linn’s single-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 MLPs operate.
The other major distinction is that Linn is aggressive in hedging its production. While other upstream partnerships like EV Energy Partners LP (NSDQ: EVEP) and Legacy Reserves LP (NSDQ: LGCY) hedge a portion of their output, Linn Energy has hedged the majority of its output. That’s especially important for natural gas, as prices should remain depressed because of strong production from the nation’s shale fields.
The firm didn’t increase its distribution in its first-quarter earnings announcement. The numbers themselves, however, continue to point in that direction later this year. Distribution coverage came in solidly at 1.15-to-1, as the company continued to complete acquisitions to boost reserves and output, particularly on the liquids side.
Management guidance is now for 1.40-to-1 distribution coverage by profit for all of 2011. That, in CEO Mark Ellis’ words, “should provide us with the ability to increase our distribution this year.”
First-quarter output rose to 312 million cubic feet per day of natural gas equivalent, a 46.5 percent jump from year-earlier levels. The average selling price of $86.24 per barrel of oil equivalent is well below current spot market prices. Operating expenses per unit of production were flat year-over-year, while transportation expenses fell 12.5 percent per unit produced. Both are remarkable achievements for any company expanding this rapidly, particularly in liquids, where prices are much higher than for gas. Buy Linn Energy LLC under 40.
Peabody Energy Corp (NYSE: BTU) is the world’s largest pure-play coal producer with operations in Australia and the western US.
Shares of Peabody Energy and other coal producers have pulled back since April, largely because of macro concerns. Softening economic data is a big part of the recent pullback, but speculation that coal demand could suffer in the near term from the earthquake that hit Japan’s Tohoku region hasn’t helped matters.
Strong demand and fears of supply disruptions because of flooding in Australia sent metallurgical (met) coal prices to the moon from January to March, supporting a huge rally in coal-related equities. As Australia’s coal mines come back online, this powerful near-term catalyst continues has waned, giving investors an excuse to take profits off the table.
But the stock appears to have found a near-term low and even rallied on June 21 after Chinese coal imports increased 22 percent in May and hit a four-month high. Continued concerns about the broader economic slowdown could keep Peabody Energy’s shares range-bound over the next few weeks, but industry- and company-specific fundamentals set the table for price appreciation in the second half of the year.
Demand for both thermal coal (used to generate electricity) and met coal (used in steelmaking) continues to rise. In the US and other developed countries, emissions standards and environmental objections are an impediment to building new coal-fired power plants.
But it’s a different story in emerging markets: Demand for electricity continues to increase at a rapid rate in India and China, both of which rely heavily on coal-fired plants. In fact, current estimates suggest that coal-fired power capacity will be the single largest source of incremental generation capacity globally from 2008 to 2020, accounting for an additional 3,516 terrawatt-hours, compared to 1,604 terrawatt-hours for natural gas and a mere 107 terrawatt-hours for solar power.
China and India are expected to add significantly to their coal-fired capacity. Between the two nations, India is the biggest growth market for coal producers. That’s because China has significant domestic coal production capacity, while India relies heavily on imports.
As a result, seaborne thermal coal supply is expected to fall 50 to 75 million metric tons short of demand 2015. Thermal coal prices will need increase to levels that incentivize producers in Australia and Indonesia to produce more coal for export. Already, coal prices in the Port of Newcastle Australia hover around $130 per metric ton, a multiyear high.
China and India are also expected to drive demand growth for seaborne met coal, which is expected to expand by as much as 550 million metric tons by 2020. Based planned mining and export projects, this market could face as much as a 10 to 30 million metric ton annual supply gap. Although prices will ease slightly as flood-related production disruptions subside, met coal prices will still need to remain high by historic comparison to incentivize investment in new or expanded production.
Peabody Energy’s extensive Australian operations position the firm to sell into the strong seaborne coal market. The company also plans to open new mines, expand existing mines and build transportation infrastructure over the next four years. Management expects these projects to expand its Australian production capacity from 27 million metric tons in 2010 to between 35 and 40 million in 2015.
Management has targeted 12 to 15 million metric tons of met coal output and 15 to 17 million metric tons of seaborne thermal coal by 2015. And with much of its 2012 Australian output not yet priced under supply contracts, the company could enjoy a lucrative year if coal prices continue to move higher.
The supply-demand balance in the US thermal coal market is nowhere near as tight. Stockpiles of thermal coal remain elevated, but strong demand has depleted stockpiles at twice the normal rate so far this year. If summer temperatures remain hot, the uptick in coal consumption could provide a measure of relief.
But depressed natural gas prices ensure that fuel switching is unlikely to occur at power plants that can burn either coal or natural gas. Meanwhile, concerns about emissions make it a good bet that utilities will prefer natural gas-fired plants when it’s time to add capacity.
In the US, I prefer companies that have the potential to grow their met coal output significantly or boast extensive operations in the low-cost Powder River Basin (PRB) or the Illinois Basin, both of which produce thermal coal. Mining outfits in North and Central Appalachia continue to suffer from rising regulatory costs and mature mines that are harder to produce.
Peabody Energy’s US operations are centered in the PRB and Illinois Basin, which produces coal that’s high in sulfur. With many plants scheduled to have advanced scrubbers installed over the next few years, the addressable market for Illinois Basin coal is growing rapidly.
PRB contains less energy per ton, but is extremely low in sulfur and cheap to produce. Mine seams in the region are much thicker than in Appalachia and many are located near the surface, eliminating the need for expensive and dangerous underground mining operations.
Historically, there hasn’t been much of an export market for PRB coal but that’s changing: Peabody Energy has exported some PRB tons to the UK, where utilities have tested it as an alternative to more expensive tons sourced from South Africa or Columbia.
But the real game-changer will be increased exports out of the western US Peabody Energy is working on a $500 million export terminal at Cherry Point, Wash. that would go online in 2015 and be capable of sending 48 million metric tons per year of PRB coal to Asia. US exports could help bridge Asia’s thermal coal supply gap and act as an escape valve for excess US inventories.
Peabody Energy sold all of its 2011 US production under contract, limiting exposure to the c weak pricing environment. In 2012 when falling stockpiles should begin to push up prices, the firm about has around one-third of its US output available for sale on the spot market. In 2013 70 to 80 percent of the company’s US production is uncovered by contract.
With a strong growth platform in Asia and advantaged US exposure, Peabody rates a buy under 72.50.By the end of this decade, Suncor Energy (TSX: SU, NYSE: SU) expects its Canadian oil sands division to account for three-quarters of the firm’s total cash flows. The remaining third will come from its offshore and international operations.
Management has set forth an aggressive plan for production growth, targeting 1 million barrels per day in annual output by the end of the decade. This goal implies annualized production growth of 8 percent over the next decade. Most of the growth will come from its oil sands operations, which management expects to grow its output at a 10 percent annualized rate.
Another major advantage for Suncor is that more than 90 percent of its total production is oil, not natural gas or NGLs. Over the past year, the firm has disposed over more than $3.5 billion worth of noncore assets, including a number of gas-producing properties. In the current environment of high international oil prices and weak US gas prices, Suncor’s oil-heavy portfolio is a winning bet.
Management recently finalized an agreement on a strategic joint venture with France-based integrated oil giant Total (NYSE: TOT). Under the terms of the deal, Suncor swapped a 19.2 percent stake in its Fort Hills oil sands production project for a 36.75 percent stake in Total’s Joslyn project in Canada. Total, an experienced player in the oil sands in its own right, will continue to operate the Josyln project; Suncor will continue to run the Fort Hills project.
Suncor also sold a 49 percent stake (retaining the majority) in its Voyageur upgrader in Canada. Production from oil sands mining projects consists of a product known as bitumen, an extraordinarily heavy, viscous hydrocarbon. Bitumen trades at a sizeable discount to crude oil because it’s tougher to refine and requires expensive treatment before it can be converted into refined products such as gasoline or jet fuel. An upgrader can convert bitumen into synthetic crude oil, a product that is similar to standard light, sweet crude oil. As you might expect, synthetic oil trades at a substantial premium to bitumen.
The Voyageur upgrader will ultimately have capacity of about 200,000 barrels per day (102,000 barrels per day for Suncor’s share), and is expected to be put into service by 2016. Upgraders are a key part of the oil sands production process, but are also extremely expensive to build. By partnering with Total–a company nearly twice Suncor’s size–the firm company reduces its capital commitments. All told, Suncor picked up USD1.75 billion in cash and about 160 million barrels in high-quality oil sands reserves from the joint venture with Total.
To meet its ambitious production goals, Suncor has announced eight major projects that will take place in the oil sands.
Source: Suncor Energy
Like any other major mining project, oil sand projects are subject to delays from time to time; however, the addition of Total as a partner increases the chances Suncor will complete projects on schedule. Meanwhile, near-term projects–including Firebag 3 and 4–appear to be progressing according to management’s master plan. In 2011 the company aims to grow its oil sands output to as much as 310,000 barrels of oil per day, up from about 280,000 barrels per day in 2010.
Take advantage of the recent pullback to buy Suncor Energy under USD48.
Proven Reserves
A core holding in any energy-focused portfolio, Chevron Corp (NYSE: CVX) boasts a balance sheet that’s stronger than many sovereign ledgers, unparalleled geographic diversity of operations and exposure to a wide range of different projects. These strengths have enabled the company to increase its dividend for 23 consecutive years and approve yet another share buyback program, this time for up to $750 million.
Given the scope of Chevron’s operations, individual projects rarely alter the company’s production mix.
At this point, the company has exited seven countries and most markets on the US east coast. Chevron will further prune its downstream portfolio in 2011, focusing on marketing assets that aren’t supported by the company’s refining operations. Management also reported strong interest in its UK refining and marketing operations.
With the global recovery in full swing, oil demand continues to rise, especially in emerging markets. Our outlook calls for oil prices to remain above $100 per barrel and approach $120 at some point in 2011. Chevron apparently agrees with this forecast: The super major increased its 2011 capital budget to $26 billion, roughly 20 percent higher than in the prior year. This announcement reflects growing confidence in the sustainability of oil prices and reflects a trend we discussed at length in Here Comes the Spending.
Much of this money will flow to projects in the Asia-Pacific region, one of the company’s key growth areas.
In addition to the massive Gorgon LNG project in Australia that will serve India, China and other key Asian markets, management also plans to direct funds to exploration and production efforts in the Gulf of Thailand. The company noted that it made five additional natural gas discoveries in Western Australia, providing additional support for Gorgon and the Wheatstone LNG project, on which management expects a final investment decision in 2011. Management affirmed that the firm has commitments for 80 to 90 percent of the LNG volumes from each of these mega projects. The company also will likely sanction a natural gas project offshore Vietnam, a prospect that has services firms salivating.
Despite the company’s extensive natural gas projects in the Asia-Pacific region, management hasn’t made too big of a splash in North American shale gas plays–a wise move, given depressed US natural gas prices. Chevron’s pending acquisition of Atlas Energy (NSDQ: ATLS), a producer in the Marcellus Shale, pales in comparison to ExxonMobil Corp’s (NYSE: XOM) oft-criticized takeout of XTO Energy. Chevron did well to secure a low-cost, long-lived asset at a relatively cheap price.
In the coming years, we look forward to more news on its unconventional plays in Poland and Romania. The company should sink its first well in its Polish acreage in 2011; should these efforts produce appreciable amounts of natural gas, demand from Continental Europe–eager to reduce its reliance on Russian supplies–could prove lucrative. Nevertheless, this project has a ways to go before it approaches full-scale production, if it ever does.
Although Chevron’s production growth may slow in the intermediate term, the company’s sound balance sheet, capable management and attractive production profile make it a core holding. That being said, at this point in the cycle, we prefer smaller names that will be able to grow output meaningfully in the near term. Chevron Corp rates a buy under 105.
Enterprise Products Partners LP (NYSE: EPD) was a model of consistency in the first quarter, reporting a record $694 million in distributable cash flow (DCF), up nearly 20 percent from the $580 million it posted a year ago. Management hiked the company’s distribution for the 27th consecutive quarter–this time to $0.5975 per unit, a 5.3 percent increase from the year-ago level.
Enterprise generated enough DCF to cover its first-quarter payout by an impressive 1.4 times. The sale of some noncore assets bolstered DCF slightly, but even with $84 million in divestments backed out, the MLP covered its distribution by about 1.25 times.
Enterprise owns a vast pipeline, storage and processing network that spans more than 50,000 miles. Throughput was strong across the board, with the MLP reporting a 6 percent in natural gas volumes to a new quarterly record, NGL fractionation volumes up 16 percent and fee-based gas processing throughput up 38 percent year over year.
Although all Enterprise’s business segments performed well in the quarter, NGL pipelines and services was the star of the show. Gross operating margin, a measure of cash flow generated by the segment, jumped $67 million from 12 months ago. A jump in volume of NGLs processed, particularly in the Rockies and Texas’ Eagle Ford Shale, drove these gains.
During Enterprise’s conference call to discuss first-quarter results, management devoted considerable time in its prepared remarks and in the subsequent Q-and-A session highlighting the growth in demand for NGLs and the consequent need to build processing plants, fractionation facilities and pipelines. Rising demand from petrochemical plants continues to drive growth in this business. Chemicals companies make ethylene and propylene–the basic building blocks of most plastics–using either naphtha derived from crude oil or ethane and propane, two NGLs. With drilling activity in liquids-rich shale plays picking up, US production of NGLs has soared. This influx of NGLs has lowered the price of these key inputs relative to the Middle East and other markets.
Petrochemicals firms continue to expand their ability to produce ethylene and propylene from NGLs. In 2011 Dow Chemical (NYSE: DOW), Westlake Chemical Corp (NYSE: WLK), ConocoPhillips (NYSE: COP) and Chevron Corp have announced major expansions to their ethylene and propylene production plants, implying a sharp increase in demand for feedstock. Enterprise’s management estimates that ethane demand alone will increase by 200,000 to 300,000 barrels per day (bbl/day) by 2015.
Analysts often ask Enterprise’s management whether the industry is overbuilding NGL-related infrastructure. Although the firm expects demand growth to support this expansion, the company also enjoys a degree of protection against overbuilding; the MLP only begins these projects after negotiating long-term contracts with that guarantee pricing and cash flow.
For example, Enterprise’s 600,000 bbl/day gas processing plant in the Eagle Ford Shale is already fully subscribed under long-term contracts. Management is now in discussions with producers to determine whether throughput volume would support additional capacity.
The MLP is currently expanding its NGL fractionation facility at the Mont Belvieu hub, adding a fifth train slated for completion in December. The fifth train is already fully contracted under 10-year deals, and Enterprise has filed permits to add another train at the facility. Management emphasized that the firm won’t build a sixth train unless long-term contracts support another addition. At this point, demand for another train appears robust.
Rising demand for NGLs translate into higher throughput volumes at Enterprise’s facilities and a need for additional capacity near fast-growing unconventional gas fields. Nevertheless, management has gradually reduced its direct exposure to NGL prices in recent years.
Like most gas processors, Enterprise historically has performed some work on an equity basis, accepting a certain volume of NGLs as compensation for use of its facilities. But management has replaced these agreements with fee-based deals that are less sensitive to commodity prices and guarantee a minimum level of cash flow over the long term. Accordingly, in the most recent quarter, Enterprise processed fewer equity volumes of NGLs while increasing its fee-based business by 38 percent from a year ago.
Exports also contributed to the strength of the Enterprise’s NGL-related businesses. The firm is upgrading its propane export terminal on the Gulf Coast, adding another 10,000 barrels per hour of export capacity. Producers have booked the terminal’s capacity completely through the end of 2012. If Enterprise had completed a planned expansion to the facility in 2010, the company would have become the world’s second-largest exporter of propane, behind only the Saudi Arabia.
Major capital spending projects will drive Enterprise’s distribution growth over the next few years. The firm already has $5 billion worth of construction initiatives underway. All of these projects are backed by long-term contracts and commitments that guarantee cash flows. Management expects the MLP to spend $3.5 billion in 2011, with balanced expended in 2012.
The largest of these undertakings is a $1.6 billion extension to its Haynesville pipeline, a project that’s slated for completion in September 2011 and is currently on time and under budget. This pipeline will carry natural gas from Louisiana’s Haynesville Shale, primarily to industrial facilities along the Gulf Coast.
The firm also has 21 projects of varying sizes underway in the Eagle Ford Shale, one of the hottest shale fields in the US. The Eagle Ford produces a combination of oil, NGLs and natural gas, all of which require dedicated midstream infrastructure. Enterprise has leveraged its existing assets in the area to become the preeminent player in the Eagle Ford.
In addition to projects already under construction, Enterprise has announced a number of undertakings that will soon begin construction. This list includes a new pipeline it’s building in conjunction with Energy Transfer Partners LP (NYSE: ETP) that will carry 400,000 bbl/day of crude oil from Cushing, Okla. to the Gulf Coast.
This pipeline will meet a critical demand at Cushing, the physical delivery point for the West Texas Intermediate crude that underlies futures contracts traded on the New York Mercantile Exchange.
Rising US imports of Canadian oil, higher domestic output from shale oil fields and an uptick in ethanol production have prompted pipeline operators to add new lines or reverse the flow of existing lines to carry crude south to Cushing and other refinery centers. This shift has not only glutted storage facilities at Cushing, but the reversed pipelines have limited flows out of the hub.
When an influx of crude oil overwhelms refining capacity, stockpiles build, and the price of WTI declines. WTI has traded at historic lows relative to similar grades of crude oil delivered to the Gulf Coast. This logistical logjam can only be resolved by the construction of new pipelines to move crude oil from Cushing to the Gulf Coast, an area that’s home to about 30 percent of the nation’s refining capacity.
Enterprise is also eyeing projects in the Rockies and in west Texas and New Mexico. The Permian Basin of Texas is of the nation’s fastest growing oil-producing regions; horizontal drilling and fracturing techniques have enabled producers to boost output from these mature fields. Most of the region’s infrastructure is decades old and insufficient to accommodate rising output.
All told, Enterprise has no shortage potential growth projects. Management has noted that the firm would need to invest $1 to $1.5 billion annually in new projects to grow its distribution at the same rate as in recent years. But management plans to spend $3.5 billion in 2011 and $2.5 billion or more per annum over the next few years; Enterprise may grow its payout at an even faster rate.
Enterprise Products Partners has consistently grown its distribution and DCF over the years and should continue to benefit from rising NGL demand. The MLP is a play on many of the same trends as Eagle Rock Energy Partners but is a far more conservative bet because of the diversity of its business lines and track record of execution. Buy Enterprise Products Partners under 45.
Big integrated oil companies are traditionally considered the most defensive plays in the energy sector. Companies such as Proven Reserves Portfolio holding 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.
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.
When we added ExxonMobil to the Proven Reserves Portfolio in Energy Value Plays, uncertainty surrounding the Macondo oil spill in the Gulf of Mexico prompted many institutional investors to rotate capital out of the energy sector. In July 2010, integrated oil names traded at their lowest valuations since the panic-induced lows of 2008.
Investor sentiment toward ExxonMobil also suffered because of concerns that the energy giant overpaid for its blockbuster acquisition of natural gas-focused producer XTO Energy.
But rising oil prices and improving fundamentals in downstream (refining and marketing) business lines suggested that the integrated oil names would benefit from a cyclical recovery. Thus far, our investment thesis has panned out: Shares of ExxonMobil are up 0.6 percent since we added the stock to the model Portfolios on July 21, 2010.
Although the stock has pulled back from its high of $88.23 on Feb. 21, the stock’s valuation is no longer as compelling. Moreover, we continue to prefer fellow Proven Reserves Portfolio holding Chevron Corp for investors seeking growth and income. Not only does Chevron boast superior production growth and leverage to oil prices, but the company also has proved much more disciplined in its acquisitions–the acquisition of gas-focused Atlas Energy in November 2010 is a case in point.
Sell ExxonMobil Corp and reallocate the proceeds to our other Portfolio holdings.
Gushers
Oasis Petroleum (NYSE: OAS) is a fast-growing, pure play on the Bakken Shale in North Dakota and Montana.
It’s a lot easier to boost production and reserves of natural gas than it is to increase oil output. But Oasis Petroleum has been breaking that mold. The firm grew its first-quarter output by 146 percent from the prior year, producing 8,090 boepd in the first quarter of 2011. Better still, 95 percent of this production was crude oil.
Oasis Petroleum’s growth story is simple: The stock represents a play on continued growth in oil production and elevated oil prices. The direction of oil prices is the key near-term driver for the stock’s performance. The shares rallied in early 2011 when oil prices soared and topped out in late February and early March–first because of concerns about weather-related production delays and later because of a pullback in crude oil prices.
With oil prices capped by concerns about global growth in the short term, the stock could lose a bit more ground or trade sideways for a few more weeks. But I expect economic data to firm up in coming weeks, which should alleviate this concern. The timing of this improvement is difficult to call, but one thing is certain: The US economy isn’t at risk of slipping into recession.
Moreover, the global oil market remains supply-constrained because of strong demand growth in developing markets and the loss of about 1.5 million barrels per day of Libyan production capacity. OPEC’s recent failure to agree to an increase in production underpins this trend. Look for global oil and refined product inventories to decline sharply in the second half of 2011, propelling oil prices higher.
As for production growth, Oasis Petroleum will continue to follow its well-established playbook of drilling additional wells in its core 300,000-plus acres in the Bakken. Management has identified 1,303 potential drilling locations across its properties, and there’s significant upside to that estimate as it gains more drilling experience in its core plays.
The firm’s main areas of operation are the West Williston area near the border of North Dakota and Montana and the East Nesson and Sanish plays located to the east in North Dakota. West Williston accounts for almost 60 percent of the firm’s total reserves, 55 percent of production and 83 percent of planned capital spending in 2011. Six of Oasis Petroleum’s seven rigs operate in this area.
Oasis brought eight wells into production in the first three months of the year and was drilling three new wells toward the end of this period. As of March 31, the company had drilled 23 wells awaiting hydraulic fracturing (hydrofracking) services. Robust drilling activity in the Bakken has outstripped the supply of hydrofracking rigs and elevated prices for this critical service. These headwinds have also weighed on the stock in recent months.
Management has addressing some of these constraints by contracting with services firms for dedicated crews. Currently, the company has two dedicated fracturing crews working on wells; a third will begin work in July.
Meanwhile, the services industry continues to the US fleet of pressure pumping trucks and equipment; this additional capacity should begin to ease completion delays and cap service cost inflation into 2012.
The stock has also pulled back because of weather-related disruptions to the company’s drilling schedule. Management cited storms and flooding as one of the reasons the firm’s second-quarter production would likely fall short of its output in the first three months of the year. The summer should provide Oasis Petroleum with an opportunity to play catch up, but several analysts have downgraded their estimates of the company’s 2011 production forecast to less than the 11,000 boepd that management has projected.
Even with these challenges, Oasis Petroleum’s 2011 output should be double 2010 levels. Moreover, weather-related disruptions and delays related to a shortage of hydrofracking capacity are temporary headwinds: The quality of the firm’s reserves is undiminished. As these challenges subside, the firm should be able to grow its annual output at a rate of 100 percent-plus over the next few years. That the stock rallied after management reduced its production guidance suggests that much of the bad news is already priced into the shares.
Management expects to complete about 69 total wells and 47 net wells in 2011–that is, some of the wells are 100 percent owned by Oasis, while others are only partially owned by the firm. Management has budgeted $402 million in capital spending on wells it operates and $39 million for the non-operated wells in which it has a stake.
There is significant upside potential to this capital spending program, and the company plans to update drilling activity guidance when it reports second quarter earnings in August. Already management has hinted that it’s working to secure two additional rigs for the back half of 2011. This could be a key catalyst for the stock, as any increase in activity would signal faster-than-expected production growth potential and easing capacity constraints.
Investors should be extremely careful when valuing Oasis Petroleum and other exploration and production firms (E&P) because traditional earnings metrics can be misleading. For example, in the first quarter, Oasis reported a loss of more than $6.8 million, largely the result of mark-to-market adjustments to the company’s hedging positions.
Like many E&P firms, Oasis Petroleum uses futures, swaps and options to lock in prices for a portion of its production and reduce exposure to volatile commodity prices. In each quarter, the company must mark the value of all of these instruments to market whether they expired in the quarter or expire years in the future. When oil and gas prices rise, these firms will report large losses on their hedges. But E&Ps don’t have to pay out cash to maintain their hedges when these instruments lose value. In the first quarter, mark-to-market adjustments reduced Oasis Petroleum’s earnings by over $31 million; without these adjustments, the company generated sizeable real earnings.
I tend to focus on operating cash flow and adjusted earnings before interest, taxation, depreciation and amortization (EBITDA) to get around these distortions. On that basis, the stock trades at a slight discount to its peer group despite the firm’s superior growth potential. In fact, the company’s first-quarter operating cash flow soared more than 200 percent from year-ago levels. The company has also already funded all of its planned 2011 capital spending and some of its 2012 budget.
With real earnings power of as high as $2.50 per share in 2012, the stock could hit $40 later this year. Buy Oasis Petroleum under 37.
An early entrant in the Haynesville Shale of Louisiana and the Eagle Ford Shale in south Texas, Petrohawk Energy (NYSE: HK) has amassed high-quality acreage positions in both plays. But the company’s astute management team is an equally important asset to shareholders.
For many gas-focused exploration and production firms, 2010-11 marks an important transitional period that will separate the long-term winners from the losers. With an oversupply of natural gas continuing to depress prices, Petrohawk Energy has focused on shoring up its balance sheet by divesting nonessential assets, increasing the liquids content in its production mix and securing leaseholds in the sweet spots of its core plays.
To this end, the company sold its acreage and midstream assets in Arkansas’ Fayetteville Shale to XTO Energy, a subsidiary of ExxonMobil Corp (NYSE: XOM), for $650 million. Management indicated that the proceeds from this transaction will be plowed into the company’s 2011 capital budget, with the goal of more than doubling its NGL, condensate and oil output to 12 percent of total production. Management estimates that 30 percent of the company’s acreage is prospective for NGLs, condensate or crude oil.
If the company meets its 2011 production guidance, liquids would account for 27 percent of revenue, a substantial uptick from 2010.
This shift will begin in the back half of 2011, when management expects the company to have secured all of its core leaseholds in the Haynesville by production. Not only will that enable Petrohawk Energy to reduce drilling activity in this prolific dry-gas field, but management will also be able to allocate more capital to its operations in the liquids-rich Eagle Ford Shale. In the final six months of 2011, the company will reduce its rig count in the Haynesville to seven from 16. In 2010 the firm sank 351 wells in the Haynesville Shale, 101 of which it operated; in 2011 Petrohawk Energy expects to drill 88 wells in the play–57 in the first half of the year and 31 in the back half.
As part of its strategic plan, Petrohawk Energy will let the leases on 135,000 acres of its noncore Haynesville territory expire, leaving it with about 225,000 acres, of which it operates about 75 percent.
Since Petrohawk Energy began drilling in the Haynesville, the company has focused on honing its drilling techniques to reduce costs and improve estimated ultimately recoverable (EUR) natural gas. Its engineers discovered that restricting flow rates both reduces production costs and increases EUR by an average of 2.5 billion cubic feet (Bcf). In 2012-13, after Petrohawk Energy secures its leasehold in the Haynesville, the company has the option to begin full-scale production. Using multi-well pads would reduce expenses substantially–management pegs costs in the Haynesville at $10.6 million per well–reducing the down time between wells and the cost of relocating equipment between drilling sites.
Management also indicated that Petrohawk Energy would likely sell its 50 percent stake in the KinderHawk, one of the largest gathering and processing systems in the Haynesville, or spin the operation off as a master limited partnership.
Despite these potential cost improvements, the company’s Haynesville acreage represents a long-term opportunity.
In the near term, Petrohawk Energy will focus on ramping up its operations in the Eagle Ford Shale, a play the company discovered in 2008. Over the past three years, the company has amassed about 357,000 commercially producible acres in the Eagle Ford. Its leasehold is located in three distinct areas: Hawkville, Black Hawk and Red Hawk.
In 2010 the company drilled 36 operated wells and five non-operated wells in Hawkville, a 225,000-acre play that comprises two distinct regions: one which contains dry gas and one which includes natural gas and condensate. Well costs in the region average $7.5 million per well. The five rigs that will operate in the region in 2011 will likely focus on the condensate-rich window. As part of an exclusive partnership with Wildcatters Portfolio holding Schlumberger, Petrohawk Energy began testing the services company’s HiWAY flow-channel hydraulic fracturing technique last fall. Early results suggest that this approach, which improves conductivity within in the reservoir rock, will elevate EURs.
The approximately 73,600-acre Black Hawk field, rich in NGLs and condensate, offers Petrohawk Energy the best returns in the current pricing environment. The company drilled 29 Black Hawk wells in 2010, generating an average of 385 barrels of condensate per million cubic feet (Mcf) of gas and 100 barrels of natural gas liquids per Mcf of gas. Management plans to sink 89 wells in 2011 in an effort to grow its liquids output.
Red Hawk is an oil-prospective area where Petrohawk Energy has sunk five wells, two of which were awaiting completion as of March 30. One of these wells didn’t produce favorable results, but the Mustang Ranch “C” #1H has flowed crude oil at a rate that suggests EUR of 200,000 barrels. The company will drill five additional wells in this area at an average cost of $5 million per well.
Petrohawk Energy balances its prolific dry-gas assets in the sweet spot of the Haynesville Shale with growing liquids production from the Eagle Ford Shale. With a sound balance sheet and a plan to generate positive cash flow by 2013, the company is headed in the right direction.
But with US natural gas prices likely to remain weak for some time, Petrohawk Energy Corp continues to rate a hold.
Valero Energy Corp (NYSE: VLO), the world’s largest independent refiner, currently operates 14 petroleum refineries–seven on the US Gulf Coast, three in the Midcontinent region, two on the West Coast, one in Canada and one in Aruba–capable of processing a total of 2.6 million barrels per day. The company’s throughput capacity will increase by a further 270,000 barrels per day (220,000 of which are crude oil) once its acquisition of Chevron’s UK Pembroke Refinery closes.
Valero’s refining operations accounted for almost 85 percent of its 2010 revenue, while the firm’s retail operations in the Americas–about 5,800 locations in the US, Aruba and Canada– represented about 11.3 percent of sales last year. The firm’s ethanol production plants in the US Corn Belt generated about 3.7 percent of 2010 revenue.
On Feb. 27, 2010, we added Valero Energy to the Gushers Portfolio as a shorter-term investment that stood to benefit from improving fundamentals. (See A New Dark Age for Refiners.) The stock has rallied 41.3 percent since it joined the model Portfolios. Although weakness in US equities has eroded our gains, cyclical trends should enable the stock to retest its 2011 high.
Broadly speaking, the refining industry continues to benefit from rising global demand for gasoline, diesel and other refined products as consumption recovers in the developed world and emerging-market demand expands at a rapid rate.
On the supply side, the overcapacity that has plagued refinery operators in the US and Europe continues to ease.
Over the past few years, integrated oil companies have sought to rationalize their downstream operations, divesting less profitable refineries in the US in favor of facilities in the Middle East and Asian emerging markets, two regions that offer superior margins and growth prospects.
Meanwhile, independent US refiners have also moved to reduce capacity, selling or closing smaller (and therefore less-efficient) plants on the East Coast–a highly competitive region that lacks access to cheaper domestically produced crude oil. The majority of oil refined at East Coast facilities arrives via tanker from Nigeria, the North Sea and other international locations.
Valero Energy estimates that these moves reduced global spare refining capacity to 5.9 million barrels per day at the end of 2010 from about 7 million barrels per day at the end of 2009. The company also got in on the act, selling its Delaware City and Paulsboro, NJ refineries in 2010.
In addition to these broad supply and demand factors, Valero Energy has benefited from a robust cost-cutting program that has lowered operating expenses from $4.41 per barrel of refined in 2008 products to $3.69 per barrel in the first quarter of 2011.
But the biggest near-term upside catalyst for Valero Energy remains the flexibility of its refineries: About 80 percent of the company’s refinery capacity can process feedstock that trades at a discount to light-sweet crude. With Mexican oil output stabilizing and rising production of heavy oil from Colombia, the refiner should reap the rewards of attractive spreads on heavy-sour and medium-sour grades of crude relative to light-sweet, waterborne crude oils.
Exporting diesel from the company’s core operations on the Gulf Coast has also generated fat margins in recent months.
Meanwhile, the company’s three facilities in the Midcontinent region stand to benefit from the widening spread between the price of West Texas Intermediate (WTI) crude (a popular US benchmark) and Brent crude oil (a European benchmark that better reflects trends in global oil demand).
WTI generally commands a slight premium to Brent crude oil, but that relationship has reversed over the past 12 months. Local supply conditions at the physical delivery point in Cushing, Okla. are the culprit: Rising US imports of Canadian oil, higher domestic output from shale oil fields and an uptick in ethanol production have prompted pipeline operators to add new lines or reverse the flow of existing lines to carry crude south to Cushing and other refinery centers.
This shift has not only glutted storage facilities at Cushing, but the reverse pipeline have limited flows out of the hub. When an influx of crude oil overwhelms refining capacity, stockpiles build, and the price of WTI declines. This logistical logjam can only be resolved by the construction of new pipelines to move crude oil from Cushing to the Gulf Coast, an area that’s home to about 30 percent of the nation’s refining capacity. This tailwind should be in play for some time.
With some of its Gulf Coast and Midcontinent refineries down for maintenance in the first quarter, the second and third quarters should feature higher throughput volumes. Nevertheless, Valero Energy Corp continues to rate a hold at current levels.
Fresh Money Buys
The stocks recommended in the three model Portfolios represent my favorite picks. The three Portfolios are designed to target different levels of risk: Proven Reserves is the most conservative; the Wildcatters names entail a bit more volatility; and Gushers are the riskier plays but have the most potential upside.
I realize that this long list of stocks can be confusing; subscribers often ask what they should buy now or where they should start. To answer that question, I’ve compiled a list of 18 Fresh Money Buys that includes 16 stocks and two hedges.
I’ve classified each recommendation by risk level–high, low or moderate. Conservative investors should focus the majority of their assets in low- and moderate-risk plays, while aggressive investors should layer in exposure to my riskier and higher-potential plays. Hedges are appropriate for investors looking to offset exposure to energy stocks.
Also note that stocks that exceed my buy target for more than two consecutive issues will either be removed from the list or the buy target will be increased.
Source: The Energy Strategist
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