One of the World's Best Oil Companies Now on Sale

With most oil-focused exploration and production companies trading at prices that aren't particularly attractive,

But neither of these concerns is likely to derail the Continental story. The company's financial health is unlikely to be an issue, given the recent uptick in oil prices. Furthermore, its Williston Basin acreage is profitable enough that Continental can generate strong returns even if differentials remain as wide as they are currently (and we don't anticipate that they will). Taken together, near-term concerns are creating an attractive opportunity in a top-tier oil company. Continental currently trades 27% below our $64 fair value estimate and is our top pick among our oil-focused E&P coverage.

Why Continental Is Undervalued Continental entered 2015 with net debt of 1.6 times trailing 12-month EBITDA, which stacks up rather well against its peers. However, the company is more heavily exposed to lower prices than most because it has no hedges in place; management opted to monetize the derivatives portfolio last fall. Even after significantly scaling back 2015 capital expenditures, free cash flow will be negative and leverage will meaningfully increase in the coming quarters; we expect net debt/EBITDA to peak at roughly 3.4 times. The company has ample liquidity in place, though, with more than $1.5 billion of undrawn capacity from its revolving credit facility.

Continental's key balance sheet issue is thus not liquidity. Its lone debt covenant stipulates that net debt must remain below 65% of total capital. This appears very unlikely, especially after the increase in oil prices during the past few months. The firm's net debt/capital was approximately 54% at the end of the fourth quarter, and we do not anticipate a covenant violation at any point during our five-year forecast window. Our analysis shows oil prices would need to reach $45 a barrel or lower to put Continental at risk of a covenant breach in the next two years.

The other near-term headwind causing concern is the weak pricing facing E&P firms in the Williston Basin, which contains the prolific Bakken Shale oil play and is where the majority of Continental's output is produced. The region's remote geographic location in North Dakota and Montana means that expensive long-distance shipping is necessary to transport crude to refinery hubs. We estimate that the midcycle cost of pipeline transport to the Gulf Coast refinery complex is roughly $6/bbl, which puts producers at an immediate disadvantage relative to peers in more accessible areas like the Permian Basin. But pipeline capacity is stretched, pushing up the cost even further. The alternative is crude-by-rail takeaway to coastal markets. That was the preferred option during 2012-13, when the Brent/West Texas Intermediate spread was wide enough that the premium price at the end point justified the additional transport cost. The subsequent narrowing of the Brent/WTI spread made pipeline transport the better solution, but there isn't enough availability, putting producers between a rock and a hard place. Managers can choose to pay a scarcity premium for the pipe or accept the higher cost of rail transport. Continental is attempting to optimize the situation by using a mixture of the two, but it is still facing weaker netbacks than competitors in different geographies.

We do expect a combination of slower production growth and additional pipeline capacity to gradually reduce the impact of the current logjam. Differentials will probably stay fairly flat over the next three years in dollar terms, but that's because oil prices are forecast to increase. On a proportionate basis, we anticipate a moderate improvement from around 12% of the benchmark to 9%. But that isn't a dramatic improvement. Our thesis that Continental's high-quality acreage is undervalued is underpinned by strong well economics, rather than a hefty improvement in differentials that may or may not materialize. If we held differentials flat instead of reducing them over time, our fair value estimate would fall to $59 per share from $64--still a 27% premium to the last close.

Attractive and Undervalued Asset Portfolio Continental's E&P activities are focused in two core areas. The first is the well-established Williston Basin in North Dakota and Montana, which contains the Bakken and Three Forks oil plays. The other is the up-and-coming South Central Oklahoma Oil Province. Both offer attractive returns despite our view that lower oil prices represent a "new normal" and that a rebound to 2014 highs is unlikely. The company has several decades' worth of undrilled locations in its resource portfolio, meaning that its growth prospects remain robust even after averaging 40% production growth during 2010-14. This is a very high-quality resource base.

Continental was an early mover in the Williston Basin's Bakken oil play; the firm has been active here since 2003 and claims the first commercially successful Bakken well in North Dakota to be both horizontally drilled and fracture-stimulated. To date, the Bakken has been the key driver of the tremendous oil production growth that North Dakota has achieved in recent years. However, the Three Forks formation, which lies underneath the Bakken Shale, has proved to be a commercially viable tight oil play in its own right.

Not all of Continental's 1.2 million net acres are prospective for both the Bakken and Three Forks, but the lion's share is. In fact, some areas contain multiple Three Forks pay zones as well. Consequently, the company's Williston Basin drilling inventory contains almost 12,000 net future well locations. Based on our rig count projections, Continental still has 15-plus years of drilling inventory in the region. Given the strong economics, Continental is well positioned for an extended period of excess returns on capital.

Falling Services Costs to Provide Meaningful Tailwind to Bakken Economics The oil industry is gradually adjusting to the reality that oil prices aren't going back to $100 anytime soon. At the start of 2015, the combination of low oil prices and prevailing capital cost levels meant even low-cost oil plays such as the Bakken offered meager returns for new wells. But oil prices have started to recover and capital costs are falling rapidly, and we don't believe either tailwind has fully played out. We therefore believe that Continental's Williston Basin acreage is still capable of generating strong economics, given its very favorable position on both the North American shale and global cost curves.

Entering 2015, Continental's expected cost of drilling and completing a Williston Basin well was $7.8 million. Using our commodity price forecasts, the firm's average Williston well would generate a 21% internal rate of return at these capital expenditure levels. While this factors in our expectation of rising oil prices, further relief is expected as costs fall. With onshore U.S. activity falling at breathtaking speed (U.S. rig counts declined more than 50% since the start of December 2014), the oil services industry has come under intense pressure. The vast majority of E&Ps in our coverage are reporting substantial cost reductions from contractors. While in the short-term costs could fall even further, we forecast capital costs to remain 20% below year-end 2014 levels. This cost deflation has a significant impact, and the economic uplift this will have on incremental investment is significant.

Bakken High-Grading Juices Long-Term Value With low oil prices straining many upstream companies' finances, there is a very strong incentive to focus on the most lucrative areas first. For Continental's Williston Basin acreage, this means the firm will prioritize its high-quality acreage in Williams, McKenzie, and Dunn counties. Management has guided that a typical well drilled in these core areas will produce 800 thousand barrels of oil equivalent, well above the expected 603 mboe average. We estimate the company has a drilling inventory of 2,600 of these 800 mboe "high-grade" wells. Given the basinwide average of 603 mboe, back-of-the-envelope math suggests estimate ultimate recovery will average roughly 550 mboe for the remainder. By front-loading with the most prolific wells, the firm is bringing production forward without altering the timing of capital outflows, and that creates value due to discounting.

In one hypothetical scenario, we assume all wells produce exactly 603 mboe--not a realistic case. The second scenario assumes the first 2,600 wells have 800 mboe EURs and the rest average 550 mboe. That's our current assumption for valuation purposes, but it's still a drastic simplification. In reality, every well will vary considerably according to the local geology. Using these two scenarios, we see that the high-grading assumption adds more than $5 per share in present value. The takeaway is that the more management concentrates on drilling its best acreage up front, the more value can be added.

Emerging SCOOP Beats Bakken While the Bakken has been the main focus for Continental during the past decade, the South Central Oklahoma Oil Province is beginning to make a much larger contribution. This is the southern leg of the Anadarko Basin in Oklahoma, which is a geologically complex feature prospective for numerous hydrocarbon plays, including the Woodford Shale. Continental has been highly active in the region and has assembled the single largest leasehold position in the SCOOP.

Like the Eagle Ford, the production mix varies across the Woodford play, and Continental is currently focusing on the condensate window. SCOOP wells are relatively expensive because of the depth but the decline rates are very shallow, which means the Woodford condensate is profitable despite the currently weak pricing for both oil and natural gas (wells in the SCOOP condensate window typically yield 20% condensate, with the remaining hydrocarbons being a mix of natural gas and natural gas liquids). The returns are decent; we estimate well IRRs to be 20% post capital cost deflation.

The potential game-changer in the SCOOP is the delineation of the Springer play, a relatively porous sand formation with a high oil content (greater than 80% of produced volumes). Springer wells have very impressive returns, which we estimate to be north of 50%, and thus better than anything else in Continental's resource portfolio. The downside is that the company has only identified around 200 undrilled locations, and this inventory will probably run in six to seven years at current drilling rates (the Springer Sand thus only accounts for about $3 per share of our fair value estimate). The company is currently conducting density pilot tests to evaluate the impact of tighter spacing on well performance--if successful, that could expand its Springer inventory. This is for now strictly considered upside, however, and we are not including this in our valuation until we have more visibility on the likelihood of success.