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

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.

Chevron looks to offshore deep water for growth

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 2010 after serving as vice chairman. He joined Chevron in 1980 and has held several different senior management roles, including president of 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/capital ratios among its peer group. Strong cash flow from operations should be sufficient to fund investments and pay the dividend; however, if oil prices retreat significantly, the company may need to increase its debt load.

Profile: 

Chevron is an integrated energy company with exploration, production, and refining operations worldwide. With production of 2.67 million of barrels of oil equivalent a day (69% oil), Chevron is the second-largest oil company in the U.S. Refineries are located in the United States, South Africa, and Asia for total refining capacity of almost 2 million barrels of oil a day. Proven reserves at year-end 2011 stood at 11.2 billion barrels of oil equivalent (58% liquids).

ConocoPhillips begins life as an independent E&P

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.

Faced with a tightening resource market, ConocoPhillips made significant acquisitions over the past decade to boost reserves and increase production. The ensuing fall in commodity prices made those acquisitions appear poorly timed, however. As a result, management changed course in past years by selling assets and reducing investment. In May, it took the final step by spinning off the downstream assets into a separate company, Phillips 66 PSX. Now the company is turning its focus to growth.

After the spin-off of its downstream businesses, ConocoPhillips ranks as the largest U.S.-based independent exploration and production firm. Based on production volumes, it is nearly twice as large as its closest peer. However, with its size come challenges, most notably ConocoPhillips' low growth rate relative to its new peer group. With a target of 3%-5% compound annual growth, ConocoPhillips matches up well with its former integrated peers, but falls short with respect to its smaller rivals. In this respect, it closely resembles Marathon Oil MRO, a former integrated now operating as an independent E&P, with a growth target in the low single digits. Both also have diversified asset profiles--onshore, offshore, LNG, oil sands, and so on--which are potentially less attractive compared with peers with much more concentrated portfolios.

That is not to say that ConocoPhillips has no opportunities to increase production and add reserves. In addition, future production additions will largely add liquids volumes or natural gas volumes from liquefied natural gas, or LNG, projects, whose prices are indexed to oil. In North America, ConocoPhillips plans to drive production growth through development of its positions in the Eagle Ford, Permian, and Bakken, as well as its Canadian SAGD operations. Internationally, growth will come from major projects in the North Sea, Malaysia, and its LNG project in Australia. In addition to contributing production of about 550 mboe/d of production by 2016, these projects are also higher-margin (assuming the current commodity price environment holds) versus current producing assets.

Ultimately, though, ConocoPhillips' size will dilute the impact of these projects, as total production is expected to be 1.8 mmboe/d in 2016. The rest of the production will come from the lower-quality assets that resulted in ConocoPhillips' weaker upstream returns compared with its integrated peers. As a result, the company would probably benefit from a continuation of asset sales beyond its current planned program of $8 billion-$10 billion over the next 12 months. The asset sales would also go toward shoring up the balance sheet and ensuring continued investment in the event of a drop in commodity prices.

Valuation

We're maintaining our fair value estimate of $52 per share after lowering our long-term natural gas price assumption to $5.40/mcf from $6.50/mcf. The lower natural gas prices reduces our fair value estimate by $2 per share, all else equal. However, we have increased our estimates for 2013 sales proceeds after the sale of a 8% stake in Kashagan for $5 billion which offsets the reduction. Our blended valuation (EBITDAX multiple and discounted cash flow-based) implies a multiple of 3.7 times 2013 EBITDA forecast of $22.4 billion.

We forecast ConocoPhillips to meet its production growth targets, which include a compound annual growth rate of 3%-5% over the next five years, and production of 1.8 million boe/d in 2016. However, we expect production volumes to remain flat to down in 2013 as new production will unlikely offset natural declines and dispositions. Sales of lower-quality assets, particularly high-cost domestic natural gas, may lower volumes but should result in an overall higher-quality portfolio. Primary growth drivers include the aforementioned Lower 48 unconventional plays, Canadian SAGD developments, and select international projects.

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 2014 and 2015 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 2014 and 2015 are $95 and $98, respectively. We assume a cost of equity of 10%, and a WACC of 8.5%.

Risk

Persistently low oil and gas prices would hurt cash flow and force ConocoPhillips to reduce its capital plans or raise debt to fund growth. The company's large projects run the risk of delays, cost inflation, and falling commodity prices, which could ruin their economics. Global operations and partnerships with national oil companies expose the company to the threat of expropriation of assets and modification of contract terms by governments.

Management & Stewardship

Ryan Lance, previously senior vice president of E&P, international, assumed the chairman and CEO role of ConocoPhillips after the spin-off. Lance's 26 years of industry experience and background in petroleum engineering should serve him well as ConocoPhillips begins life as an independent E&P. 

His strategy appears to be a bit of a departure from years past when efforts focused on a shrink-to-grow strategy. There will be some additional asset sales in the next year, but at the same time management is ramping up capital spending to drive production growth. Time will tell if this strategy is successful. While ConocoPhillips does have some attractive assets that warrant investment, the recent strategy of increasing shareholder returns and selling assets has proved successful and could have been continued. While shareholder returns will remain a priority, management is giving itself little room for error with its capital plan. As a result, spending may have to be curtailed if commodity prices fall, resulting in lower growth than targeted.

Overview

Financial Health: 

ConocoPhillips holds about $1.3 billion in cash and $2.5 billion in restricted cash at the end of the third quarter. During the quarter it repaid $2 billion in debt, reducing its debt/capital ratio to 31% from 33%. The restricted cash could go toward additional debt repayment to get the company to its long-term target of 25-30%

Profile: 

ConocoPhillips is a U.S.-based independent exploration and production firm. In 2011, it produced 867,000 barrels per day of oil and natural gas liquids and 4.5 billion cubic feet a day of natural gas, primarily from the United States, Canada, Norway, and the United Kingdom. Proven reserves at year-end 2011 stood at 8.4 billion barrels of oil equivalent, 41% of which are natural gas.

Exxon is positioned to compete in a world with diminishing resources

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 is always an issue. Past events in Russia, Nigeria, and Venezuela underscore the risk associated with doing business in those countries. These risks will only become greater as Exxon expands its global production portfolio through partnerships with NOCs. By investing in large, capital-intensive projects, Exxon also runs the risk that commodity prices will decrease dramatically, making those projects no longer economical. Deterioration of refining fundamentals in the U.S. and Europe may continue to damage profitability long after an economic recovery.

Management & Stewardship

Rex Tillerson became chairman and CEO in 2006. Previously, he served as president. He has spent his career 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 from operations remains sufficient to finance capital expenditures while increasing dividend payments and buying back stock. More important, the large cash position and access to cheap debt give the company resources 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.

Schlumberger is well-positioned to grab huge international pricing power

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.

Despite its aggressive push toward oilier plays, Chesapeake remains heavily tied to natural gas

by Mark Hanson, CFA (Morningstar Analyst)

Chesapeake Energy CHK announced Tuesday a definitive agreement to sell the majority of its remaining midstream assets to Access Midstream Partners ACMP (formerly Chesapeake Midstream Partners) for $2.16 billion. The transaction is expected to close later this month. Chesapeake had announced a letter of intent for these assets in the third quarter. The company expects to sell an additional $425 million of midstream properties in the first part of next year, bringing the total proceeds for all of its midstream assets to $4.9 billion. Assuming the Access deal closes this month, Chesapeake will have sold just under $11 billion in assets in 2012. Other near-term monetizations to keep an eye out for include the sale of the company's D-J Basin and noncore Eagle Ford acreage as well as a joint venture across its Mississippian leasehold. Our fair value estimate remains at $26 per share.

Chesapeake is among the most aggressive operators in the U.S. E&P space, able to quickly build dominant positions in emerging plays through its vast network of land brokers and a general willingness to offer more favorable lease terms than its competitors. While this approach has helped Chesapeake amass a portfolio that comprises almost every leading unconventional play in the U.S., it has also led to ongoing questions about the sustainability of the firm's business model, given its propensity to outspend available cash flow. Despite the potential for some fits and starts over the next few years as Chesapeake works through how to best monetize its extensive inventory, we're bullish on the company's ability to increase production and reserves going forward, given management's knack for creatively financing its operations and the relevance (that is, the attractiveness to third-party investors) of its current leasehold positions.

Chesapeake's portfolio includes more than 15 million net acres of onshore oil and gas assets. The firm holds leading positions in the Barnett, Haynesville/Bossier, Marcellus, Eagle Ford, Niobrara, Permian, Utica, and Anadarko Basin regions, among others, and continues to build its presence in liquids-rich plays as part of an ongoing strategy to diversify away from natural gas. Given impending lease expirations (or a sizable inventory of wells waiting on completion) in a number of its plays, we expect Chesapeake to push its drilling and completion plans hard over the next several quarters in order to hold acreage and bring production on line, especially in the Haynesville and Barnett regions. There is generally less urgency in Chesapeake's Marcellus, Eagle Ford, Utica, and Granite Wash acreage, although we expect joint venture considerations and takeaway commitments to drive drilling activity in these regions to a certain extent.

Chesapeake's "land rush" strategy has led to charges that the firm marginalizes the economics in its plays, given its willingness to accord higher royalties and pay top dollar for leases. The company would counter that it is locking up once-in-a-lifetime assets and would point to subsequent transactions that validate its above-market cost basis. We concede that Chesapeake appears skilled at securing large blocks of land within emerging plays--a combination of its "land machine" and technical skill--and find it hard to argue with the prices that have been paid by third parties for portions of its acreage. That said, Chesapeake's approach has at times led to serious problems for the firm, as in 2008, when a steep drop in natural gas prices forced the company to sell assets and raise external capital to help shore up its balance sheet. To Chesapeake's credit, the financing methods it put in place at that time--most notably volumetric production payments, or VPPs, and a handful of joint ventures--have helped the company stay afloat longer than most thought possible and served as an essential financing tool for the firm as it expands its operations. Nevertheless, we believe these financial maneuvers--in particular JVs--have benefited Chesapeake to the detriment of the broader E&P industry, in large part through carries that help support uneconomic drilling meant to achieve HBP status.

Based on the success it has had with such structures, we expect Chesapeake to continue utilizing JVs and VPPs going forward. The firm has entered into seven JVs and 10 VPPs since late 2007, generating total proceeds of approximately $23 billion ($2.1 billion of which remains to be earned over the next several years in the form of drilling carries). Chesapeake's key JV partnerships include Statoil STO in the Marcellus, Total TOT in the Barnett and Utica, and CNOOC Ltd. CEO in the Eagle Ford and Niobrara.

Chesapeake is more vertically integrated than most large producers. The firm takes an active stance on costs by investing directly in its service providers: Chesapeake holds interests in the fifth-largest rig contractor, the fourth-largest hydraulic fracturing company, and the second-largest compression business in the U.S. and also operates its own core sample testing center. We highlight the potential for takeaway bottlenecks in some of the firm's newer plays--particularly the Haynesville, Marcellus, and Eagle Ford regions.

In short, despite Chesapeake's past missteps and some ongoing uncertainty as to how the firm best realizes the potential of its inventory, we expect additional JVs, VPPs, and trust offerings to help fund drilling activity across the firm's 15 million net acres, leading to growth in production and reserves throughout our forecast period.

Valuation

We are lowering our fair value estimate for Chesapeake from $27 to $26 after incorporating the firm's most recent results and management's latest guidance and updating our midcycle natural gas price assumption, from $6.50 per mcf to $5.40 per mcf. Excluding any impact from our updated midcycle price, our estimate would have increased by $4, to $31 per share. Our new fair value estimate implies a forward 2013 enterprise value/EBITDAX multiple of 6.8 times, and is based on our five-year discounted cash flow model and an assessment of trading multiples, comparable transactions, and longer-term resource potential.

We project average daily net production of 3.9 Bcfe in 2012, 4.2 Bcfe in 2013, and 4.6 Bcfe in 2014, representing a 12% compound annual growth rate over 2011 levels. Chesapeake remains one of the most active drillers in the U.S. E&P industry, with approximately 100 operated rigs across its acreage. The firm's push to achieve HBP status in certain plays, along with JV partnership obligations and minimum takeaway commitments, should continue to fuel high levels of drilling activity over the next few years, funded in part through Chesapeake's approximately $2.1 billion in remaining drilling carries. We expect the firm's Eagle Ford and Anadarko Basin acreage to drive most of its production growth throughout our forecast period. Within the Anadarko Basin, we forecast net production of 909 mmcfe/d in 2012, 1,247 mcfe/d in 2013, and 1,538 mmcfe/d in 2014. Across Chesapeake's Eagle Ford acreage, we forecast net production growing from 277 mmcfe/d in 2012 to 577 mmcfe/d by 2014.

Driven by production growth and an ongoing shift toward liquids, we forecast EBITDA of $3.2 billion in 2012, $5.3 billion in 2013, and $6.3 billion in 2014.

Risk

Chesapeake's biggest risk is a substantial and prolonged drop in oil and gas prices, which would depress profits, slow development plans, and reduce the value of its properties. Other risks include a disruption in the asset market, which would limit the company's ability to monetize its acreage holdings; a shrinking universe of potential JV partners with which to transact going forward; execution risk within Chesapeake's emerging plays (in particular the Haynesville, Marcellus, Eagle Ford, Anadarko Basin, Utica, and Niobrara regions); potential midstream bottlenecks, especially within the Marcellus and Eagle Ford; and regulatory headwinds that could ultimately eat into profitability.

Management & Stewardship

Chesapeake is led by CEO Aubrey McClendon, who, up until his announced ouster from the role earlier this year, also served as chairman for the past 23 years. McClendon maintains a fairly visible and controversial presence in the E&P space, in part through his role as a de facto spokesman for the U.S. natural gas industry as well as his highly promotional approach to Chesapeake's business dealings.

Chesapeake has generally exhibited poor stewardship of shareholder capital over time. The firm has roughly doubled its share count since 2005 thanks to subpar operating performance, an overstretched balance sheet, and the need to continually bridge the gap between cash flow and capital expenditures. Investors have suffered as a result, with Chesapeake's shares badly lagging those of its peer group over the past several years and returns well below our estimated cost of capital for the last three years. 

Despite this, Chesapeake's top officers routinely collect some of the biggest compensation packages in the E&P industry. The firm's decision to award McClendon $75 million in incentive pay in late 2008 was especially controversial and viewed by many as nothing more than a make-whole for McClendon in the wake of a margin call that forced him to liquidate substantially all his Chesapeake stock holdings. 

We think the now infamous founder well participation program wasn't necessarily a bad idea and in theory should have aligned McClendon's interests with those of the company. The big issue we have with the FWPP was that it allowed McClendon to borrow to fund his obligations under the program. Doing so enabled him to effectively short-circuit the alignment of interests this program was intended to promote. It also created a potential conflict once McClendon borrowed from some of the same institutions that had relationships with Chesapeake on a corporate level.

Overview

Financial Health: 

Chesapeake has historically paired its aggressive operating strategy with a similarly aggressive financing strategy. From 2005 to 2011, the firm's capital spending significantly outpaced operating cash flow, resulting in net borrowing of more than $10 billion and the implementation of several nontraditional financing vehicles to help meet cash shortfalls. During this time, Chesapeake's debt/capital ratio averaged 45%, with average debt/proven reserves and debt/EBITDAX ratios of $0.89 per mcfe and 2.6 times, respectively. The firm has taken a number of steps to improve its financial position during the last several quarters, including the redemption of close to $3 billion in senior notes and the issuance of more than $3 billion in preferred securities.

We expect Chesapeake to continue its strategy of funding investment activity through a combination of operating cash flow, VPPs, JV transactions, asset sales, trust offerings, and debt financing through 2014, with free cash flow becoming positive by late 2015. We forecast an average debt/capital ratio of 49% through 2015, with the firm's debt/proven reserves and debt/EBITDAX ratios remaining elevated as well. We estimate the firm's outstanding obligations for its VPPs will be $1.2 billion by year-end 2015. (Note that none of the preceding credit metrics incorporates Chesapeake's ongoing VPP obligations.)

Profile: 

Chesapeake Energy, based in Oklahoma City, explores for, produces, and markets primarily natural gas within the U.S. The firm focuses on unconventional plays, with large positions in the Barnett, Eagle Ford, Haynesville, and Marcellus Shales, as well as leaseholds in a number of liquids-rich basins. Chesapeake controls more than 15 million net acres across its properties. At year-end 2011, the firm's proved reserves totaled 18.8 trillion cubic feet equivalent, with daily production of 3.5 Bcfe. Natural gas made up 85% of proved reserves.