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.
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