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16 Aralık 2012 Pazar

Schlumberger is well-positioned to grab huge international pricing power

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by Stephen Ellis (Morningstar Analyst)

Schlumberger's SLB diversified operations did well in a difficult quarter marked by uncertainty overseas and a challenging environment in North America. Both oilfield services revenue and pretax operating income were up 2% sequentially to $10.6 billion and $2.1 billion. Like peer Halliburton HAL, Schlumberger was exposed to a weak pressure pumping market in North America, but revenue only declined 2% sequentially to $3.3 billion, and operating margins just over 200 basis points to 18.6%. This is a better performance than Halliburton's 5% revenue decline and 660-basis-point margin compression over the same time frame; we think the outperformance is due to Schlumberger's smaller pressure pumping operations, but also the fact that Schlumberger didn't purchase overly large quantities of guar at the top of the market. The international market continued to do fairly well this quarter, with Schlumberger noting improved pricing and tight capacity for seismic, wireline, drilling and measurement, and well testing. However, there continues to be significant uncertainty surrounding the global economy as Chinese growth slows. At this point, the balance of oil supply and demand remains tight, with OPEC spare capacity at five-year lows and continued production challenges in non-OPEC countries. However, we caution that as the global economies continue to struggle and GDP and oil demand growth remain stagnant, the tight balance could change, pushing down oil prices, services demand, and Schlumberger's financial results.
Schlumberger is one of the top firms in the oil services industry. In our view, the company is well-positioned to benefit from the industry's current weakness and future rebound, given its financial strength, geographical and product diversification, well-regarded research labs, and unique technology acquisition strategy. We believe the company's focus on building out a product set by making small software-oriented acquisitions to provide deeper insights into solving oil field issues will result in an edge over smaller peers when conditions improve. This strategy is geared toward winning large integrated project-management contracts with national oil companies (where Schlumberger excels), which offer ample opportunities to sell additional services from its wide-ranging portfolio.
Schlumberger's comprehensive services portfolio offers pressure pumping services, seismic services, and integrated project-management efforts. The company's services are typically used to extract oil and gas from wells, an effort that has grown more complicated with the increased complexity and depth of the oil and gas reservoirs under development. We think Schlumberger's one-stop approach earns it customer loyalty, which results in premium prices for its services. Further, we think the company's large product portfolio lets it package many of its products into a single attractive offering, making it very difficult for more narrowly focused competitors to win work. Accordingly, the firm generally has the leading market share in all its product lines. This factor, combined with its R&D strength and technology approach, leads us to assign a wide economic moat to the company.
We believe Schlumberger's market share gains are driven by its substantial R&D investments, which are supported by a clever acquisition strategy. Oil and gas companies will rapidly adopt new products if they can see the value proposition. Schlumberger has had numerous R&D successes during the last few years, including its seismic Q-technology, which has grown into a billion-dollar business. The firm's latest success appears to be its HiWAY fracturing technique, which enables higher well productivity while using less water and proppant. The technology has been successfully deployed in both North America, where it made up 15% of Schlumberger's stages in late 2011, and internationally, with Rosneft ROSN using it in West Siberia. The R&D successes mean Schlumberger can consistently commercialize its research efforts for rich payoffs, which we think peers find harder to accomplish. Further, the company's acquisition strategy feeds its R&D advantages. We believe the firm thinks more like a technology firm and acquires soft assets (such as software), whereas its peers think like consumer goods companies and acquire hard assets (like a Latin American oil services firm). We think these types of technology deals, such as openhole logging services provider ThruBit in late 2011, keep the firm ahead of competitors and positioned for long-term growth around the world.
Still, as Schlumberger competes in many global markets, we believe it faces some risks. Political risk is always a concern when governments can destroy firms for political gain (as we've seen in Russia) or nationalize assets (as we've seen in Venezuela and Argentina). Also, an inability to commercialize key technology could cost the firm project wins and reduce the impact of its heavy investment in its globalized workforce. Finally, we believe that recent cash-for-oil deals with Brazil and Russia could mean a larger Chinese oil services presence in the countries in the future. In our view, one of China's goals behind the deals is to secure larger roles for its oil services arms overseas, which will ultimately mean more competition for Schlumberger.
Valuation

We are keeping our fair value estimate at $75 per share. While lower guar prices should benefit Schlumberger in the latter half of 2012, we remain concerned about the impact of lower oil demand from Europe and China and the resulting pressure on global oil prices, which would lead to pressure on oil services spending budgets. Our fair value estimate implies a forward 2013 P/E multiple of 20 times and a forward 2013 EV/EBITDA multiple of 10.2 times.
We expect lower profitability in North America in 2012, thanks to the negative effects of continued gas-to-oil rig switching. Rig demand is also dropping, which means more potential oversupply issues for the services industry. International markets such as Brazil, Iraq, and Russia all offer growth opportunities for the next few years. Overall, we see Schlumberger's revenue growth at 11% in 2012 (which is affected by the Wilson sale), mostly thanks to strength overseas. Over the long term, we believe many of Schlumberger's markets can grow 8% annually (on average) as the increasing complexity of the oil and gas reservoirs requires more services to fully develop. We expect the firm's long-term operating margin in North America to be around 22%. In the international markets, we believe margins will be 23%, as the markets gradually improve and Schlumberger reaps higher prices. We expect the company's capital expenditures in 2012 and 2013 to be $4.2 billion and $4.3 billion (which includes M&A activity) as it continues to build out its international presence.
Risk

As with all oil services companies, Schlumberger could face difficult times if oil and gas prices had a significant and sustained fall. Its reliance on technology and acquisitions to drive revenue could backfire if a competitor developed better technology or if an acquisition failed to perform up to expectations. The company's extensive infrastructure in Russia could prove to be a liability if the government decides to treat service companies like it has treated operators such as Yukos.
Management & Stewardship

New CEO Paal Kibsgaard leads one of the deepest and strongest management teams in the oil services industry. Longtime CEO Andrew Gould remained as chairman of the board until April 2012. We think the firm's disclosures in its financial statements and on its website are very good and provide much insight into the business and industry. During Gould's tenure, capital allocation was superb, and the firm made many useful technology-related acquisitions to maintain its R&D edge over its peers. We have yet to see evidence of Kibsgaard's ability to allocate capital, but we expect respectable returns. The company's return on invested capital has consistently been well ahead of its cost of capital over the years, and we don't expect that dynamic to change in the near future. We view the Smith acquisition as a significant strategic win in terms of improving Schlumberger's integrated product offerings, but Halliburton has already established its leadership in this area. Overall, the management team has generally strengthened Schlumberger's competitive position over time and has delivered excellent results for shareholders.
Gould stepped down from the CEO role on Aug. 1, 2011, after many years of top-tier leadership. His role at the company has been changing during the last few years, and we believe his most recent efforts have been focused on managing the integration of Smith. The deal for Smith in early 2010 and Gould's retirement now was planned so that Kibsgaard can focus on execution rather than integrating the two companies. Kibsgaard joined Schlumberger in 1997 as a reservoir engineer in Saudi Arabia and quickly progressed through a variety of global management positions in the company, including vice president of engineering, manufacturing, and sustaining. By laying the groundwork well in advance, Gould set Schlumberger up for a very smooth CEO transition, in our view.
Overview

Financial Health:
As Schlumberger historically has generated strong free cash flow, its financial health remains quite healthy. At the end of 2012, we estimate Schlumberger's debt/capital ratio will stand at 24%, its 2012 EBITDA will be about 40 times its interest expense, and its total debt/EBITDA ratio will stand at 1.0 times. We believe Schlumberger is appropriately leveraged, given the cyclical nature of the oil services industry. Unlike peers, Schlumberger has avoided large debt-driven deals during the last few years, and the resulting balance sheet strength should let it acquire some opportunistic bargains.
Profile:
Schlumberger is one of the largest oil services companies, with more than 113,000 employees across 85 countries. It offers a near-complete array of oil services--from seismic surveys to artificial lifting--to oil majors, exploration and production companies, and national oil companies. In 2011, it generated $39.5 billion in revenue and $4.8 billion in net income.

Exxon is positioned to compete in a world with diminishing resources

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by Allen Good (Morningstar Analyst)

Imperial Oil IMO has confirmed reports that its Kearl oil sands mine (a joint venture with ExxonMobil XOM) may be delayed until January 2013 on account of weather. While we had high hopes that the project would achieve first oil in December, we knew the biggest risk was weather. Taking into account the wind chill, the average hourly temperature in the Fort McMurray region was:

28 F (-2 C) in October
3 F (-16 C) in November
-12 F (-25 C) in December (Dec. 1-10)

More telling than the average temperature has been the minimum (coldest) hourly temperature:

-0.4 F (-18 C) in October;
-40 F (-40 C) in November;
-31 F (-35 C) in December (Dec. 1-10)

When we consider the extreme cold in October and into December, we are not surprised by the delay. For Imperial, we were forecasting production from Kearl of 4.4 thousand barrels per day for the fourth quarter but are now assuming no production during the quarter. The expected impact is a CAD 0.03 per share reduction in cash flow with no change to our 2013 production estimates or fair value estimate.
For ExxonMobil, the impact will probably be negligible, given the already anticipated late startup. However, without any Kearl volumes, Exxon is likely to find it more difficult to meet its full-year production target. There is no change in our fair value estimate.
ExxonMobil sets itself apart from the other majors as a superior capital allocator and operator. Through a relentless pursuit of efficiency, technology, development, and operational improvement, it consistently delivers higher returns on capital relative to peers. However, we think ongoing low U.S. natural gas prices are likely to prove a drag on returns, which could fall behind those of more oil-exposed peers.
Longer term, we think Exxon will probably retain its top spot, but delivering returns on par with historical levels could be more difficult as it faces the ongoing challenge of reserve replacement. With a majority of the world's remaining resources in government hands, opportunities for the company to expand its large production base are limited. However, we believe Exxon's experience and expertise, particularly with large projects, should allow it to successfully compete for resources.
While we believe Exxon has an advantage in the current environment, that does not necessarily mean production and reserve gains will come easily or cheaply. Exxon's need for projects of a certain size in order to contribute meaningfully to its production profile and justify investment leaves it with an diminishing set of opportunities. In addition, investing exclusively in large projects exposes the company to a variety of risks including overinvestment risk, execution risk, and budgetary risk. Future projects will also probably rely on resources with higher extraction costs because of their lower quality (bitumen), location (deeper water) or stimulation requirement (fracturing).
Greater competition is also becoming an issue. Many available large projects will be done in partnership with national oil companies. To gain access, Exxon must not only demonstrate its value but may also have to agree to production-sharing agreements that are not as advantageous as in the past. More often, management is faced with a tough decision: Take less favorable terms on more projects, or focus on projects where its expertise is highly valued. A good example of the latter case is Exxon's recent deal with Rosneft to explore for oil in the Russian Arctic. If Exxon is able to exploit similar opportunities where it can add oil reserves with attractive terms thanks to its value proposition, then it can probably continue to deliver superior returns on capital.
Faced with these challenges, Exxon is turning to relative political safe havens to drive growth like the United States and Canada. In the U.S., growth will largely come from resources added with the acquisition of XTO. While the acquisition largely consisted of natural gas reserves and production, it also held acreage in tight oil plays to which Exxon has subsequently added, namely in the Bakken and Duvernay. It is now also shifting its drilling activities to these more liquid-rich plays in light of low prices. Exxon has cut its rig count to 50 from 70 last year and is using two thirds of those rigs in liquid-rich plays as opposed to less than half previously. That said, we still expect returns to suffer as low prices depress profits and shale gas invested capital sits idle.
Exxon also has promising offshore discoveries in the Gulf of Mexico that should be developed in the coming years. In Canada, Exxon's reserves are primarily oil sands, both mining and in situ. Its largest project, Kearl, will come on line in late 2012. While Kearl initially will add about 100 thousand barrels a day of oil production, oil sands mining projects typically fall on the upper end of the cost curve. We think Kearl is better positioned than other projects because it does not require an upgrader, but it still is indicative of the move to higher-cost resources by Exxon in the face of increased resource nationalism.
Another way Exxon is tackling its growth/reserve replacement issues is by investing in projects like oil sands and LNG that produce at plateau production levels for longer than traditional projects, some up to decades, and reduce its overall decline rates. Also, relatively little reinvestment is required after the large initial up-front capital, resulting in significant free cash flow generation after startup. We estimate nearly 40% of Exxon's production will come from these types of projects by 2016. However, most are large projects, especially the LNG developments, and thus hold the aforementioned risks.
Despite growing investment in the U.S., Exxon is not stepping off the international stage or away from political risk. Asia and Africa continue to be the company's largest producing regions and we expect them to continue as such, with numerous projects scheduled to come on line over the next five years in Nigeria, Angola, and Kazakhstan. Exxon also has the potential for shale resources in Europe and South America that would allow it to leverage its acquired unconventional technology and bolster its value proposition and competitive advantage in the global competition for resources.
Valuation

We are maintaining our fair value estimate of $91 per share after lowering our long-term natural gas price assumption from $6.50 per thousand cubic feet to $5.40. The lower natural gas prices reduces our fair value by $5, all else equal. However, the reduction is largely offset by the rise in short-term oil prices since our last update. Our long-term forecasts and assumptions incorporate a more challenging operating environment as well as a decline in returns on capital relative to historical performance over our forecast period.
Our fair value estimate is approximately 4.9 times our 2013 EBITDA estimate of $86 billion. In our discounted cash flow model, our benchmark oil and gas prices are based on Nymex futures contracts for 2012-14. For natural gas, we use $2.87/mcf in 2012, $4.08 in 2013, and $4.08 in 2014. Our long-term natural gas price assumptions for 2015 and 2016 are $5.40. For oil, we use Brent prices of $112 per barrel in 2012, $108 in 2013, and $104 in 2014. Our long-term oil price assumptions for 2015 and 2016 are $99 and $102, respectively. We assume a cost of equity of 8%.
We forecast a compound annual growth rate for production of 1.1% during our forecast period. Growth should be more robust in outer years after falling approximately 3% in 2012. We expect Exxon to actually increase oil volumes (1.8%) at a greater rate than natural gas (0.4%) over our forecast period thanks to large project startups over the next three years. Our forecast is slightly below management's forecast to compensate for the potential negative effects of higher oil prices related to production-sharing contracts as well as the risk associated with larger projects. Full realization of management's guidance could offer upside to our valuation, while extensive delays or reduced U.S. natural gas production due to lower prices could result in downside risk.
Refining margins have staged a recovery in the past year. However, we model slight margin weakness over the next couple of years with an improvement in the later years of our forecast. While ExxonMobil should benefit from highly complex facilities and access to growth markets, it has only limited exposure to wide U.S. domestic sweet crude discounts. However, that should change in the future as additional pipeline capacity brings domestic and Canadian crude to the Gulf Coast, improving ExxonMobil's access to discount feedstock. Meanwhile, we anticipate chemical earnings to remain tied to economic activity.
Risk

For a company with global operations, geopolitical risk isalways an issue. Past events in Russia, Nigeria, and Venezuelaunderscore the risk associated with doing business in thosecountries. These risks will only become greater as Exxon expandsits global production portfolio through partnerships with NOCs. Byinvesting in large, capital-intensive projects, Exxon also runs therisk that commodity prices will decrease dramatically, making thoseprojects no longer economical. Deterioration of refiningfundamentals in the U.S. and Europe may continue to damageprofitability long after an economic recovery.
Management & Stewardship

Rex Tillerson became chairman and CEO in 2006. Previously, he served as president. He has spent hiscareer with Exxon, beginning in 1975 as a production engineer. The recent acquisition of XTO Energy raised concerns that he may be straying from the returns-focused strategy that has made ExxonMobil great and instead investing in growth for the sake of growth. ExxonMobil's subsequent performance has lent weight to this argument as gas volumes have grown while prices have fallen, resulting in declining returns. However, while the acquisition has proven to be ill-timed given the drop in natural gas prices, we think ultimately it can deliver returns that meet ExxonMobil's requirements as prices rise and it leverages XTO's knowledge to exploit unconventional plays globally.
ExxonMobil's record of generating shareholder returns deserves an exemplary stewardship rating, in our opinion. Despite the XTO acquisition, we think Tillerson is likely to continue a disciplined capital allocation strategy, given his previous statements, and deliver the high returns that his predecessor did. Recent efforts to exploit more lucrative Kurdistan reserves at the risk of losing pre-existing, but likely lower-returning, Iraqi contracts provides us some evidence to his focus on returns. As a result, we are inclined to maintain the exemplary rating.
Returns to shareholders also remain a focus, with share repurchases the primary tool used to return excess cash. However, Tillerson recently acknowledged ExxonMobil's relatively low yield and indicated higher payouts could be in the future.
Overview

Financial Health:
As one of the few remaining firms with an AAA credit rating,ExxonMobil's financial health is beyond reproach. Cash flow fromoperations remains sufficient to finance capital expenditures whileincreasing dividend payments and buying back stock. More important,the large cash position and access to cheap debt give the companyresources to make opportune acquisitions.
Profile:
Exxon is an integrated oil and gas company that explores for, produces, and refines oil around the world. In 2011, it produced 2.4 million barrels of oil and 12.1 billion cubic feet of natural gas a day. At year-end 2011, reserves stood at 17.7 billion barrels of oil equivalent (plus 7.3 billion for equity companies), 47% of which are oil. The company is the world's largest refiner and one of the world's largest manufacturers of commodity and specialty chemicals.

ConocoPhillips begins life as an independent E&P

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by Allen Good (Morningstar Analyst)

Chevron looks to offshore deep water for growth

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by Allen Good (Morningstar Analyst)

We've lowered our estimate of the marginal cost of domestic natural gas from $6.50 per thousand cubic feet to $5.40 per mcf, driven primarily by an updated analytical approach. Because our upstream valuation methodology incorporates an out-year marginal cost-based view on oil and gas prices, it follows that a reduction in marginal cost results in a revaluation of our gas-weighted upstream energy coverage universe. For those firms most leveraged to gas production, our fair value estimates have decreased 10%-15%. However, oil and liquids exposure provides insulation from any meaningful change to fair value estimates for the majority of our upstream coverage list. Our valuations also reflect our current midcycle view on oil, incorporating $95 per barrel West Texas Intermediate and $99 per barrel Brent. In addition, we assume that North American natural gas liquids composite prices trade between 40% and 50% of crude oil throughout our forecast period.
We remain bullish on domestic natural gas and continue to see considerable upside to current gas prices. Our analysis indicates that Henry Hub gas prices tend to track marginal cost quite well over longer time intervals, strongly suggesting a rebound from today's $3.70 per mcf within a few years. This is reflected in our stock calls, as for the most part our 4- and 5-star stocks remain just that, even after updating our models with a lower out-year gas price assumption. We continue to view Ultra Petroleum UPL and Devon Energy DVN as the most attractive gas-weighted names, Apache APA and Canadian Natural Resources CNQ as the most attractive mixed-oil/gas stocks, and Suncor SU and Occidental Petroleum OXY as the most attractive oil-weighted firms.
Like its fellow supermajor integrated peers, Chevron is finding it increasingly difficult to expand production and add reserves in a world with a shrinking investable resource base. Much of the remaining pools of cheap, easily accessible resources large enough to interest the larger players reside in the hands of governments and national oil companies. Resource-rich nations are bolstering their nationally owned or controlled energy companies in an attempt to capture more value for their own countries. While this can create an opportunity for firms that can offer oil and gas development expertise, it also forces them to greater lengths to acquire reserves. In Chevron's case, that means focusing on deep-water exploration.
In recent years, Chevron concentrated its exploration efforts on a few key areas that have yielded a high level of exploration success. Discoveries in those key areas of the Gulf of Mexico, West Africa, northwest Australia, and the Gulf of Thailand have already begun to contribute production and will serve as the growth engine for Chevron in the years to come, setting it up for peer-leading growth beginning in 2014-15. Success in each of these regions also demonstrates Chevron's ability to thrive in a highly competitive environment with limited access to resources. Exploration and production efforts in West Africa and the Gulf of Thailand involve numerous partnerships with governments and national oil companies. In the Gulf of Mexico, Chevron's success rests on its ability to deliver production from highly technical projects as it pushes into deeper water to secure resources. In Australia, Chevron is relying on liquefied natural gas to capture the value of massive offshore deposits of natural gas.
The two LNG projects in Australia, Gorgon and Wheatstone, will be the primary drivers of growth in the next few years. Gorgon, slated for startup in late 2014, will add more than 200 thousand barrels of oil equivalent per day of production at peak production. Wheatstone, scheduled for startup in 2016, will add almost another 200 mboe/d. In addition to the volume growth, we see other benefits. Both projects allow for future expansion, given the physical space for additional trains and ongoing discoveries in the region. LNG production, while primarily gas volumes, has prices indexed to oil, which should allow Chevron to preserve its peer-leading liquids exposure. Also, projects like LNG with long-plateau production levels that require little additional capital expenditure help to reduce decline rates while generating significant free cash flow to support reinvestment elsewhere or shareholder returns.
While Chevron's focus on deep water, and by extension larger projects, brings production growth, it also holds substantial risk. Since the cost of drilling offshore wells can be more than $100 million, exploration risks can be quite high. Even after a discovery is made, Chevron then must confront engineering risk. Deep-water projects are technically challenging, and they can often incur higher costs and delays before production comes on line.
Cost inflation in areas with high levels of activity such as Western Australia can jeopardize the economics of projects if not properly managed. This is a specific threat to Chevron's two large LNG projects as other operators in the country have had to revise project budgets upward based on currency appreciation and materials inflation. However, we estimate that even if costs for Gorgon's first three trains come in at $55 billion (compared with $37.5 billion originally), Chevron will still break even on the project. Also, once operational, the four-train development will deliver more than $3 billion in free cash flow annually to Chevron.
Our valuation hinges on Chevron's ability to deliver production from these deep-water and LNG projects on time and within budget. As recent events in Brazil and Nigeria illustrate, incidents at deep-water operations that result in oil spills put the company at risk of negative headlines at the least and potentially stiff monetary fines or permanent cessation of operations at worst. On the downstream front, Chevron is well positioned for the future with highly complex facilities that serve key developing markets. Not only are its facilities capable of producing lower-quality crudes, but many also have the flexibility to produce highly valued diesel. Diesel consumption is likely to drive future refined product demand growth, particularly in the United States.
However, Chevron has a measured view of the long-term economics of the refining business. As a result, over the past two years, Chevron has restructured its downstream operations and shed assets, which should lead to improved returns. Also, returns should improve as it shifts downstream capital to its higher-return chemical operations to fund projects designed to take advantage of low-cost feedstock in the Middle East and North America.
Valuation

We are maintaining our fair value estimate of $125 per share after lowering our long-term natural gas price assumption from $6.50 per thousand cubic feet to $5.40/mcf. The lower natural gas prices reduce our fair value estimate by $5 per share, all else equal. However, the reduction is largely offset by the rise in short-term oil prices since our last update.
Our fair value estimate is approximately 3.9 times our 2013 EBITDA forecast of $60 billion. We expect natural gas to contribute a greater share of production, about 36%, by 2016 compared with 31% in 2011. However, a significant portion of these volumes will be LNG, whose pricing is linked to oil. Also, close to 75% of Chevron's oil production comes from international assets and is tied to higher Brent prices.
In our discounted cash flow model, our benchmark oil and gas prices are based on Nymex futures contracts for 2012-14. For natural gas, we use $2.87 per thousand cubic feet in 2012, $4.08 in 2013, and $4.31 in 2014. Our long-term natural gas price assumptions for 2015 and 2016 are $5.40. For oil, we use Brent pricing of $112 per barrel in 2012, $108 in 2013, and $104 in 2014. Our long-term oil price assumptions for 2015 and 2016 are $99 and $102, respectively.
In our forecast for the next few years, we expect Chevron to see little production growth. Also, rising oil prices will probably mean Chevron's production-sharing contracts yield lower oil volumes. Production growth should increase to 4%-5% by the end of our forecast period as large LNG projects start up. In the downstream segment, we expect profitability to improve in the coming years as a result of improved refining margins, stronger chemical results, and the benefit of recent restructuring.
Risk

Chevron's profits and cash flow are largely tied to oil and gas production and could suffer as a result of a significant fall in prices. Additionally, long-term price depreciation would expose the company to overinvestment risk as current projects would see returns languish with weaker economics. Regardless of commodity prices, these projects also are subject to cost overruns or completion delays. Many of the company's new investments are in politically challenging areas that sometimes have fickle leaders and populations hostile to outside firms. With significant exposure to the Gulf Coast, extended delays in permitting could result in higher costs and delayed production volumes.
Management & Stewardship

John Watson assumed the CEO and chairman position in 2010after serving as vice chairman. He joined Chevron in 1980 and hasheld several different senior management roles, including presidentof international exploration and production and CFO. We like that Watson has a mix of financial and operational experience that should lead to better capital allocation decisions, in our opinion. We also like that other senior executives have significant operating experience in various parts of Chevron's business throughout the world.
We give Watson high marks for his leadership to date, despite the stream of negative headlines. His greatest challenges may be yet to come as Chevron develops its multi-billion-dollar LNG projects and fights an ongoing legal battle over environmental damages in Ecuador. Positive outcomes on both fronts would speak volumes about current leadership.
We also like Chevron's measured approach to acquiring U.S. unconventional assets and the fact it stayed out of places like southern Iraq where the returns are questionable. We think this speaks to Chevron's overall emphasis on returns over growth and is reflected in its returns on capital, which rate near the highest in the sector. Unlike other majors, Chevron has been reluctant to rush into acquisitions or add projects in foreign countries where it cannot add value for the host countries or shareholders. We think this is wise, given the increasingly competitive environment for resources and the willingness of some international competitors to pay for access. As a direct result, Chevron's upstream segment's returns have outperformed peers of late. Also, the firm remains focused on cash returns to shareholders. Its preferred method is through dividends, which it has historically steadily increased. Given these factors, we think Chevron earns an exemplary stewardship grade.
Overview

Financial Health:
Chevron has one of the strongest balance sheets and lowest debt/capitalratios among its peer group. Strong cash flow fromoperations should be sufficient to fund investments and pay thedividend; however, if oil prices retreat significantly, the company may need toincrease its debt load.
Profile:
Chevron is an integrated energy company with exploration,production, and refining operations worldwide. With production of2.67 million of barrels of oil equivalent a day (69% oil), Chevronis the second-largest oil company in the U.S. Refineries arelocated in the United States, South Africa, and Asia for totalrefining capacity of almost 2 million barrels of oil a day.Proven reserves at year-end 2011 stood at 11.2 billion barrels ofoil equivalent (58% liquids).

BP is changing in ways that would have been hard to imagine at the beginning of 2010

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by Stephen Simko, CFA (Morningstar Analyst)

We've lowered our estimate of the marginal cost of domestic natural gas from $6.50 per thousand cubic feet to $5.40 per mcf, driven primarily by an updated analytical approach. Because our upstream valuation methodology incorporates an out-year marginal cost-based view on oil and gas prices, it follows that a reduction in marginal cost results in a revaluation of our gas-weighted upstream energy coverage universe. For those firms most leveraged to gas production, our fair value estimates have decreased 10%-15%. However, oil and liquids exposure provides insulation from any meaningful change to fair value estimates for the majority of our upstream coverage list. Our valuations also reflect our current midcycle view on oil, incorporating $95 per barrel West Texas Intermediate and $99 per barrel Brent. In addition, we assume that North American natural gas liquids composite prices trade between 40% and 50% of crude oil throughout our forecast period.
We remain bullish on domestic natural gas and continue to see considerable upside to current gas prices. Our analysis indicates that Henry Hub gas prices tend to track marginal cost quite well over longer time intervals, strongly suggesting a rebound from today's $3.70 per mcf within a few years. This is reflected in our stock calls, as for the most part our 4- and 5-star stocks remain just that, even after updating our models with a lower out-year gas price assumption. We continue to view Ultra Petroleum UPL and Devon Energy DVN as the most attractive gas-weighted names, Apache APA and Canadian Natural Resources CNQ as the most attractive mixed-oil/gas stocks, and Suncor SU and Occidental Petroleum OXY as the most attractive oil-weighted firms.
When viewing the oil majors' prospects, one key competitive challenge stares down each and every company: replacing reserves is becoming increasingly difficult and costly. To be sure, there's a lot of oil left in the world, but finding low-cost barrels of oil has never been harder, in no small part because many governments now don't allow Western oil companies access to their resources. Excluding Russia, BP produced the equivalent of 920 million barrels of oil and gas in 2011; this represents the number of new reserves it needs to book each year if its resource base isn't to shrink. But there simply are not 920 million barrels of conventional oil reserves (that is, the lowest-cost barrels) accessible to BP in a given year. This has created a resource scramble that is increasingly focused on non-conventional resources: deep-water, oil sands, LNG, and unconventionals (shale gas/tight oil). What this means is at a given level of energy prices, we expect BP's returns on capital will be lower in future years as non-conventional resources are much costlier to develop and produce.Of course, BP has much to worry about beyond higher cost reserves, with its major concerns being the unfolding aftermath of Macondo and its future in Russia now that it has tied itself up with Rosneft ROSN. Although largely independent of each other, taken together these are likely to change the shape of BP in ways that would have been hard to imagine at the beginning of 2010.
The impact from Macondo on BP's operations has been tremendous. Net pretax cash outflows have been $30 billion to date, and our expectation is $10 billion-$20 billion more is still to flow out before all is said and done (our valuation assumes $15.5 billion from 2013 onward). Further, BP has been forced to sell off the equivalent of 10% of its production and reserves during a period of high oil prices. Beyond the fines and penalties that remain to be paid, a further $3 billion-$4 billion of asset sales are planned before the end of 2013. BP was producing 3 million non-Russian barrels of equivalent per day of oil and gas before Macondo. When the dust settles, volumes will likely be 20%-25% below this level.
The other major near-term issue is what the new tie-up with Rosneft means to BP's future. BP actually owned 1.25% of Rosneft's outstanding shares prior to the recent deal, so the company actually now owns 19.75%. But this isn't the same old Rosneft; after purchasing TNK-BP, Rosneft is now by far the largest publicly traded oil producer in the world. Further, it has a huge resource base from which it can keep production growing for years to come. Of course BP only owns 19.75% of this company rather than the 50% it held of TNK-BP (a huge company in its own right). Our initial review shows that BP's proved reserves are likely to increase by 400 mmboe because of this deal, while production and profits are likely to be slightly lower than they were from TNK-BP.
Though in many respects this looks like a decent deal (BP gets $12.3 billion in cash in addition to 18.5% of Rosneft's shares), Russia is, of course, not the friendliest of places for Western oil companies. In our view, two considerations could make this deal less attractive than it appears at first blush: future cash flows and sovereign risk. With respect to cash flows, what matters to BP is the cash dividends received. First, Rosneft intends to pay out much less in dividends than TNK-BP did, meaning cash flows from Russia are likely to be billions less in the coming years than they have been of late. Further, Rosneft is spending $40 billion in cash to acquire TNK-BP (on top of giving $14 billion in stock to BP) and with only $5 billion of cash on hand, it will have to take on a lot debt to finance this deal. Put together, it's clear the outstanding cash flow numbers from TNK-BP (BP put in $4 billion and assets in 2003 and received $18 billion in dividends) are unlikely to be repeated, and in a crisis BP could be asked to contribute capital in the future.
The second risk is impossible to quantify but there's no question to its existence: How long will Russia be OK with BP owning 20% of its national oil champion? And if Rosneft ever is re-nationalized (undoubtedly a possibility over the long term), will BP be compensated in a fair manner? The pessimistic answer to this question is that Western oil companies have been getting burned in Russia since the Soviets took power, and if the Kremlin moves expel BP from Russia there's likely little the company can do about it. The optimistic rebuttal to this is that Russia's state energy companies have paid fair prices for recent deals (for example, TNK-BP and Sibneft), so BP could be compensated in a reasonable manner if and when it heads for the exits.
Valuation

We are maintaining our fair value estimate of $46 per ADR. We are lowering our long-term natural gas price assumption from $6.50/Mcf to $5.40/Mcf; however, only 11% of BP's 2015 production will derive from North American natural gas, which makes the valuation impact from this change immaterial.
In light of the TNK-BP sale and Rosneft tie-up we have removed TNK-BP from our BP valuation, and our forecast financials don't include any Russian business activities. To value BP's Rosneft stake we add $12.3 billion in cash to our valuation and the market value of the 18.5% stake it will own. We discount the value of BP's stake by 25% to account for illiquidity/risk, which currently equates to a value of $9.5 billion. Though our fair value increases, so does BP's risk, which isn't what investors were hoping for given its high-risk story. Accordingly, we are raising our uncertainty rating to high from medium. For oil and gas prices, our forecasts use prices based on Nymex futures contracts for 2012-14 and our own midcycle price assumptions for 2015-16. Brent oil pricing: $112 per barrel in 2012, $108 in 2013, $104 in 2014, $99 in 2015, and $102 in 2016. WTI oil pricing: $94 per barrel in 2012, $91 in 2013, $91 in 2014, $95 in 2015, and $98 in 2016. Henry Hub natural gas (U.S.): $2.87 per Mcf in 2012, $4.08 in 2013, $4.31 in 2014, $5.40 in 2015, and $5.40 in 2016.
Cash outflows relating to Macondo lower our fair value by approximately $4 per ADR (roughly $3 billion in cash outflows destroys about $1 of value per share). Our key assumptions are: $1.2 billion in cash outflows will occur during the rest of 2012. $4.5 billion of cash outflows to settle criminal charges and SEC securities charges are modeled as disclosed by the company. In 2013, we project a $2 billion cash settlement from Transocean. We also project a few hundred million dollars in various oil spill-related spending annually in each of the next five years.
Beyond these considerations, BP remains liable for various lawsuits and penalties, the most important of which are Clean Water Act and claims filed by states in the Gulf Coast region. We currently model BP's share of CWA fines to $7.7 billion. Also, we assume that settling all other Macondo-related liabilities will total $3.5 billion. All told, these cash outflows sum up to $15.5 billion from 2013 onward. Projecting remaining oil spill outlays is very speculative, but it's clear billions more will flow out the door during the next few years.
Risk

BP's valuation carries heightened uncertainty due to the uncertainties surrounding the Macondo oil spill and its high-stakes exposure to the Russian government through its Rosneft partnership. With Macondo, the final dollar amounts of various fines and lawsuits are impossible to predict, but the reality is that remaining outflows are likely to fall in the $10 billion-$20 billion range. With respect to its 20% stake in Rosneft, being a foreign company that holds such a large stake in Russia's national oil company creates a significant amount of sovereign risk. This last risk cannot be overstated, and it's likely the market won't give BP full credit for the value of its investment.
Beyond these company-specific issues, BP's profits and cash flow are largely tied to oil and gas production and are highly leveraged to movements in the price of oil and to a lesser extent, natural gas. Periods of prolonged low energy prices weaken returns on capital and new oil and gas projects would be unlikely to generate their projected economic results. BP employs huge amounts of capital in building out its production portfolio, and cost overruns and/or completion delays are continued sources of uncertainty. Going forward, greater reliance on highly technical projects is likely to increase these risks.
Management & Stewardship

In the wake of the Macondo oil spill, Robert Dudley took over BP with the job of stabilizing the firm and rebuilding its very tarnished reputation. To date, Dudley has run BP well enough, although his hardest tests lie ahead when he has to determine how to shape the company after Macondo and TNK-BP. Macondo is the second time BP has had to shore up its safety record in recent years, the first being the Texas City refinery explosion of 2005. Other notable incidents of the past decade include 6,500 barrels of oil leaking from the Trans-Alaska pipeline in 2007 and a record $303 million fine levied by the U.S. Commodities Futures Trading Commission for BP traders trying to corner the propane market in 2003-04. Even after Texas City, BP continued to notch up a great deal more safety violations than its peers in its U.S. refining operations, which along with Macondo, does make us believe that BP was fundamentally flawed in how it was running its operations. It's impossible to say if BP is finally going to change its ways in terms of safety performance; after all, Texas City clearly did not usher in a safety-first culture in the way the Valdez oil spill did for Exxon. But Macondo is an event of such monumental value destruction that if it can't shake BP to the core and instill change, nothing can. Putting together its poor safety record and execution issues, we consider BP management to be a poor steward of shareholder capital.
Overview

Financial Health:
Minus a material and prolonged decline in oil and gas prices, BP's $38 billion divestment program ($35 billion of which has been completed), cash proceeds from selling TNK-BP ($12.3 billion) and operating cash flows should be sufficient to cover capital investment, dividends, and Macondo-related fines and lawsuits. In fact, we think BP's financial health is very good and the company will be able to increase capital spending, dividends, and/or share repurchases as soon as 2013. The company reinstated its dividend at $0.42 per ADR and has since raised it to $0.48, which remains below the pre-Macondo level of $0.84. Management clearly wants to restore the dividend to prior levels, but it likely won't be until 2015 before this is possible.
Profile:
BP is an integrated oil and gas firm with operations across six continents. BP's upstream operations (excluding TNK-BP) produced 2.5 million barrels of oil equivalent per day during 2011. Downstream operations include refining, chemicals, lubricants, and service stations. Due to the Macondo oil spill, BP is amid a $38 billion divestiture program, of which $35 billion has been completed to date. Included in these divestitures are roughly 10% of the company's pre-spill production and reserves.

12 Aralık 2012 Çarşamba

What Is Gold's Role? Gold's role as disaster insurance in a time of easy money.

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By Michael Rawson, CFA is an ETF analyst with Morningstar.

At a joint meeting of the International Monetary Fund and World Bank held in Tokyo in October, Federal Reserve chairman Ben Bernanke said that central bankers in emerging economies should "refrain from intervening in foreign-exchange markets, thereby allowing the currency to rise." Of course, for one currency to rise, another must fall. It can be argued that the Fed chairman was suggesting that the U.S. dollar is overvalued and could be due for a decline.
Elsewhere Bernanke has emphasized on several occasions that monetary policy, controlled by the central bank, is doing all it can to spur the economy and that fiscal policy, the purview of the government, needs to be more aggressive. In recent decades, monetary policy has been run independently of fiscal policy. That said, many claim that the Fed has become increasingly politicized, and some politicians have gone so far as to suggest that Ben Bernanke be fired or that the government should strip control of monetary policy from the Fed and return to the gold standard. Meanwhile, though the Fed’s policies of quantitative easing are potentially inflationary, inflation has been benign to date. But many investors, fearful of equities since the financial crisis and spooked by the specter of inflation in an era of "QEternity," have increasingly considered gold for their portfolios. Gold has historically proved to be an effective inflation hedge, and a declining dollar is positive for bullion prices. But just what role should gold play in a traditional stock and bond portfolio? In this article, we will examine where gold might fit in your portfolio and highlight our favorite exchange-traded funds that offer exposure to the yellow metal.
Hard to Value, Hard to Ignore
Unlike productive assets such as farmland or dividend-paying stocks, gold seems to lack the fundamental characteristics necessary for valuation. With gold there will be no stream of widgets to sell or cash flows to discount. Warren Buffett famously mused on gold: “[Gold] gets dug out of the ground in Africa, or someplace. Then we melt it down, dig another hole, bury it again and pay people to stand around guarding it. It has no utility. Anyone watching from Mars would be scratching their head.” While Martians may be scratching their heads, it seems that many rational investors covet gold. Ben Bernanke has argued that gold is not money and that it is held by central banks largely out of tradition. He has also offered some insight into the way many investors value gold. The Fed chairman has said that people hold gold as a protection against tail risk--low probability events with big implications. These so-called “black swans” might include a massive sell-off in the stock market or hyperinflation.
Reliable data for gold prices from the London Bullion Market Association extends back to 1973. If we regress the price of gold on movements in the stock market and next year’s inflation back to 1973, we find that the price of gold responds positively to both increases in inflation and declines in the stock market.Two time periods play a big role in explaining this relationship. The stock market fell 15% in 1973 and a further 26% in 1974. Meanwhile, inflation jumped from 3% in 1972 to 9% in 1973 and ramped up to 12% in 1974. During this span, gold proved a fantastic inflation hedge, climbing 73% in 1973 and 66% in 1974. Gold proved its worth as a tail-risk hedge again during the most recent financial crisis, rising 4% in 2008 when the S&P 500 Index plummeted 37%. For the 10 years through year-end 2011, gold was up 450%, trouncing the 30% return of the S&P 500 Index.
The charts below show the annual performance of gold based on sorting and bucketing stocks or inflation into five buckets.

- source: Morningstar Analysts
- source: Morningstar Analysts

How Much to Own? And Where Does It Fit?
An asset that rises in value when most other assets decline should be very valuable. It can be thought of as a kind of insurance. To insure against bad times (that is, the aforementioned tail risks), people are willing to accept small losses in good times. Because the price of gold is sensitive to changes in inflation or the prospects of a disaster, a little bit goes a long way. For those who have decided to own some gold in their portfolios, we feel that 5% is an appropriate weight. This study from Campbell Harvey and Claude Erb suggests a 2% weight of gold in the market portfolio while an Ibbotson study suggests at least a 7% weight.So, how does gold fit into a portfolio? A 60/40 portfolio of stocks and bonds will have a slightly higher return and slightly lower risk when holding a 5% position in gold, resulting in a higher risk-adjusted return.
From 1973 through September 2012, a 60/40 portfolio of the S&P 500 Index and intermediate-term government bonds had an annualized return of 9.4% and an annualized standard deviation of 9.9%. Adding a 5% position to gold and reducing stocks to 58% and bonds to 37% would increase the portfolio's annualized return to 9.6% and reduce its annualized standard deviation to 9.4%. That slightly higher return is mostly a function of the time period chosen. Over the past hundred years or so, stocks have massively outperformed gold. So, over the long term, investors could have earned higher returns in stocks and bonds but the overall portfolio risk would have been lower with a small position in gold, resulting in better risk-adjusted returns.

Three charts of America’s bright energy future

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by Carpe Diem BlogPosted: 08 Dec 2012 10:29 AM PST
Here are three charts based on the new Annual Energy Outlook 2013 from the U.S. Department of Energy:
1. The first chart above shows that the U.S. is expected to produce domestically almost 83% of the energy consumed this year, which will be the highest level of energy self-sufficiency since 1991, more than two decades ago. For a quarter century, U.S. energy production as a share of domestic energy consumed was on a gradual decline, falling from a peak production share of more than 91% of the energy consumed in 1982 to below a 70% share by 2005.
But then hydraulic fracturing, horizontal drilling and the shale revolution happened and dramatically changed the course of U.S. energy production for the 21st century. Starting around 2008, advanced drilling technologies started accessing trapped hydrocarbons in shale rock and U.S. energy production started surging – to an all-time record high this year for natural gas and to a 14-year high in 2012 for domestic crude oil. The new upward trend in energy self-sufficiency is expected to continue for at least the next three decades, and by 2033 America’s own domestically produced energy will provide more than 90% of the total energy consumed.

2. The chart above shows the impact of the shale revolution on America’s production of domestic natural gas. Ten years ago, shale gas production was an insignificant 2% share of America’s total natural gas production. Thanks to advances in hydraulic fracturing, that share has been rising and shale gas will provide more than one-third of the natural gas produced domestically this year. By the year 2038 shale gas will represent more than half of U.S. natural gas production and will continue on an upward trajectory from there.

3. The chart above shows the Department of Energy’s estimates of CO2 emissions per capita from 2010 to 2040. Total energy-related carbon emissions are expected to fall to a 20-year low this year, and a per-capita basis will be the lowest since at least 1973 when the Department of Energy’s data begins. From the current level of 17 tons per capita, we can expect CO2 emissions per capita to fall to 14 tons per capita in 2040, a 25.2% decrease. One of the largest contributing factors in the reduction of CO2 emissions is the switch from coal to gas for electricity generation and the switch from fuel oil to natural gas as a fuel source for heating homes and commercial buildings.
MP: The new projections from the Department of Energy through the year 2040 paint a very bright picture for America’s energy, economic, and environmental future in the first half of the 21^st century. Thanks to advanced drilling technologies and the shale revolution, we can expect ongoing increases in domestic oil and gas production, which will:
a) keep adding thousands of new direct jobs for drilling activities and thousands of more indirect jobs throughout the energy supply chain,b) attract billions of dollars in new investment capital, and therefore,c) continue to generate energy-related prosperity in states like North Dakota, Texas, Oklahoma, Pennsylvania and Ohio.
As we access more of America’s bonanza of shale gas and oil, the country’s energy self-sufficiency will gradually increase to new high record levels, while at the same time we’ll see carbon emissions per person fall to new record low levels. America’s bright energy future continues to provide one of the best reasons to be optimistic and bullish about the U.S. economy.