Oily Stocks To Watch

With West Texas Intermediate prices firming back above $90 per barrel, it’s as if some of the momentum so lacking amid the languor of energy equities late in 2012 has crept back into the energy sector.

Anticipation of the Seaway pipeline expansion helped spark the move in WTI at year-end. However, energy equities showed little inclination to follow suit until the drama of the Fiscal Cliff played out. Then, in just the first several weeks of 2013, the EPX Index of energy equities chalked up a gain of 5.7%, ahead of 4.8% for the S&P 500.

Other factors have helped build confidence, too, including signs of the Chinese economy finding its footing, European economic travails easing, and the U.S. housing sector continuing to strengthen.

In addition, in its first monthly report of 2013, the International Energy Agency boosted its global oil demand estimate for 2013 by 240,000 barrels per day to 90.8 million barrels daily, centered on stronger demand data from China. This is up from an estimated 89.8 million barrels per day for 2012, revised higher on fourth-quarter demand from the U.S., China and Brazil.

So, assuming a continuing backdrop of $90-plus WTI prices, what crude oil-levered stocks are favored by analysts in the current environment?

Leverage to the Permian Basin, with its multistacked pays, including the Wolfcamp, offers attractive upside for two names followed by Joseph Allman, an analyst with J.P. Morgan in New York. For investors able to use small-cap names, he favors Approach Resources Inc. with a price target of $44.50. For investors looking for a larger market-cap name, he recommends Pioneer Natural Resources, with a price target of $146. Price targets are set based on companies’ year-end 2013 estimated net asset value (NAV) per share.

Pioneer, based in Irving, Texas, has legacy assets in the Spraberry, and last year had as many as 12 rigs running in its Eagle Ford horizontal play.

“But the most exciting thing about Pioneer is the Wolfcamp horizontal play,” says Allman, who notes the company sought a joint-venture partner to accelerate drilling in the southern part of the play. “Initial drilling results by Pioneer and others suggest the northern part could be even better.”

At press time, Pioneer announced that Sinochem had been brought in as that joint-venture partner for the southern acreage. Drilling will focus on roughly 200,000 contiguous acres, located mainly in Upton, Reagan and Irion counties. Pioneer says the acreage offers more than 4,000 potential horizontal development locations and a total gross resource potential of more than 2 billion barrels equivalent, with 90% liquids content.

The terms of the deal, under which Sinochem bought a 40% stake, call for total proceeds to Pioneer of $1.7 billion, made up of an upfront cash payment of $500 million and a drilling carry of $1.2 billion over six years. Eighty-six horizontal Wolfcamp wells are to be drilled in 2013, 120 wells in 2014 and 165 wells in 2015.

While four rigs have been running in its southern acreage as Pioneer presses to hold acreage ahead of lease expirations, a fifth rig has been added in the north to delineate the play in Midland, Martin and Gaines counties.

“A catalyst for the stock would be positive results in the northern part of its acreage,” says Allman. Although limited data are available on Pioneer’s drilling in the area, results from a nearby operator to the north and east, Laredo Petroleum Inc. “appear to be better than wells in the south.”

In terms of estimated ultimate recoveries (EURs) for wells on its southern acreage, Pioneer guides to 575,000 barrels, assuming a 7,000-foot lateral and 30 to 35 frac stages. In his modeling of Pioneer, Allman adopts a somewhat more conservative assumption, using an EUR of 450,000 barrels. This is in line with EURs indicated by peer companies operating in the area, which in some cases have had wells coming on with initial production (IP) rates higher than Pioneer’s 600-barrel-equivalentper-day average.

Some analysts think oil price and demand factors spell upside for these names.

Even with the more conservative EUR assumption in his NAV model, Allman sees about 30% upside to a $146-price target, based on Pioneer trading at a small premium to NAV, in line with peers. Catalysts abound: potential results on its expansive northern acreage, the joint-venture announcement in the south, and—tapping into a new zone on its legacy Spraberry properties—news of more horizontal Jo Mills wells to follow on from two wells that had IPs of 554 and 308 barrels equivalent per day in fourth-quarter 2012.

Another pick, Approach Resources, Fort Worth, Texas, offers “probably the most leverage to the Wolfcamp horizontal play,” says All-man, given the company’s single-basin focus and smaller size. In addition, prior to the upsurge in drilling by Pioneer, it was second only to much larger independent EOG Resources Inc. in terms of activity in the play. As a result, “besides EOG, Approach has the most data and the longest production history in the play.”

Allman likes Approach “because it is one of the cheapest stocks in our universe.” Having sold off on a combination of oil weakness and infrastructure issues last year, the stock now offers some 70% upside to a price target of $44.50, which in turn represents a 7% discount to NAV. Like Pioneer, the NAV for Approach is based on a Wolfcamp EUR of 450,000 barrels.

Last year’s “stumbles” over infrastructure issues, hampering liquids and natural gas sales, are now “behind them,” says Allman, who projects 40% growth in production for Approach this year, well in excess of the median 13% growth of its peers. The faster growth, coupled with the steep discount to NAV, more than justifies a premium 6.3x multiple of enterprise value to 2013 EBITDA (earnings before interest, depreciation and amortization), versus a group multiple of 3.9x.

“With production growing at 40%, it will work its way into that higher multiple,” says Allman.

With a 2013 capital budget set at $260 million, versus estimated cash flow of $140 million next year, Allman says some investors may have concerns relating to equity issuance—equity has been issued in each of the last three years. However, Approach is thought more likely to tap the high-yield market, and in the meantime has close to $200 million available on its credit lines.

In terms of drilling inventory, Approach has guided to 350 horizontal Wolfcamp “B” locations and 150 Wolfcamp “C” locations. An update may include increasing the horizontal well count at the expense of its remaining vertical well program, plus adding Wolfcamp “A” locations—possibly on a 1-to-1 ratio with its “B” locations. However, whatever the composition, Allman is already modeling an inventory of more than 800 locations on Approach’s145,000 net acres—enough, he points out, to sustain drilling for over a decade.

Away from the Wolfcamp play, Denbury Re- sources is another inexpensive stock that is poised to benefit from a change in investor sentiment, Allman says.

“Denbury is essentially a pure-play EOR company,” he notes, referring to the company’s core assets involved in enhanced oil recovery.

Following recent transactions—the sale of its conventional Bakken assets, plus the purchase of two fields suited for CO2 flooding—Denbury will have strengthened a base of assets within a “company with 10 years of visible double-digit production growth from relatively low risk projects,” Allman says.

Moreover, having spent the past year revamping its internal processes for monitoring and forecasting production, especially on EOR projects, Denbury “is likely to meet or beat its production guidance going forward. What’s hurt them in the past has been missing their numbers, and now they are also adding conservatism to their guidance.”

In addition to a projected change in investor sentiment, Allman notes other developments due this year: the start of EOR production in the Rockies for the first time, as well as injection of anthropogenic CO2 in the Gulf Coast area. “Plus they’re doing a stock buyback.”

The price target of $26.50 represents upside of 45%.

Permian liquids

Joe Magner, senior research analyst with Macquarie Capital, likes Cimarex Energy as its accelerating momentum in Permian liquids production comes into clearer focus and with stronger cost control. And, the company’s upward trend in overall volumes no longer faces headwinds from natural gas declines, particularly in the Gulf Coast. Production growth is estimated at 13% for 2013, up from an earlier forecast of 8%.

Magner upgraded Cimarex to outperform from neutral following “strong” third-quarter results. His target price on the stock currently stands at $72.

“The company’s third quarter marked an inflection point,” he says. It provided “solid evidence that the company is building sustainable momentum in the Permian Basin as a product of its disciplined approach, focused not just on growing production but also on lowering costs.”

Denver-based Cimarex has three core operating areas. Oil growth is driven by the Permian, where it is active in the Bone Spring and Wolfcamp horizontal plays of the Delaware Basin. Here Magner projects gathering momentum to deliver 21% growth in 2013. In the Midcontinent area, driven by its Cana play, output is projected to rise 14%. In the Gulf Coast, however, production is expected to fall by 33% in 2013, following a drop of over 60% in 2012.

“If you isolate oil growth over the last two years, the liquids side of the story has been very impressive,” says Magner. “You now have liquids growth really driving overall production growth out of the Permian and Cana, and it can now shine through rather than being offset by the Gulf Coast declines.”

Gulf Coast volumes, which once ran at over 200 million cubic feet per day, are down to about 50 million daily and are “now so small, declines have little effect.”

In the Permian, says Magner, “they’re still seeing great results in the Second and Third Bone Spring plays, and the repeatability of the Wolfcamp wells has gotten better.” Bone Spring well costs are down some $500,000 from the start of last year, while Wolfcamp wells cost about $7.6 million, down from $8.5 million in second-quarter 2012. In addition, while earlier in the year there were issues concerning water-handling costs and constraints on water disposal, “a lot of that is behind them now.”

Cimarex is also on the move in the Midcontinent Cana play, with plans for four rigs to run through the winter and a completion schedule to run through May. Given weakness in natural gas liquids (NGLs), Magner assumes no significant increase in NGL prices; in any event, at recent prices, it is roughly “a wash” as to whether NGLs are stripped out or not. Cimarex estimates after-tax returns in the Cana are currently similar to those in the Wolfcamp, but below those in the Bone Spring.

Two areas could compete with Cana for capex dollars: One is a new shallow-oil development in the Midcontinent, for which little data have been released. Another is a 100,000-acre position in the Delaware Basin, which Cimarex has mapped as being prospective for two Bone Spring sands. The acreage is near where Concho Resources is reported to have had good well results recently, and Cimarex has begun drilling operations.

Following firming in energy stocks in early 2013, Cimarex offers almost 15% upside to a $72 target price. On an enterprise-to-2013 EBITDA multiple, it trades at a 5.3x multiple versus the peer group average of 6.4x.

What about names linked to oil production offshore? Energy XXI (Bermuda) Ltd., with a production mix skewed 70% to oil, is favored by Magner. While the Houston firm is in some quarters better known for its participation in the shallow-water, ultra-deep play with McMoRan Exploration Co.—with particular focus on the Davy Jones I exploration well—Magner sees enough catalysts elsewhere to rate the stock Outperform.

For example, “in the absence of any meaningful progress on the shallow water, ultra-deep program,” says Magner, “the focus on the operational side has shifted more to the company’s horizontal program, where the first few wells have yielded great initial production rates—2,000 to 3,000 barrels per day plus.” The company’s first horizontal well, on West Delta 73, came on production in 2012’s fourth quarter at almost 3,000 barrels per day and averaged 2,000 per day in its first month of production.

Compared with a typical vertical well, the attraction of the horizontal wells is clear. The IP of 3,000 barrels daily from the first horizontal well compares with 1,000 per day for its vertical counterpart, while reserves for three initial horizontal wells are estimated at 1.2 million barrels or more compared with 350,000 barrels. Well costs should run only about 15% higher than with vertical wells. Energy XXI has 16 horizontal wells in inventory for its 2013 fiscal year ending June 30, 2013.

In total, some 80 to 90 horizontal drilling locations have been identified so far, “but I don’t think that is a full-scale assessment of what they might be seeing over time as they continue to evaluate more of their fields,” says Magner. “I think we’ll see that program continue to gain momentum.”

On the exploration front, in its Vermilion Block joint-venture area with ExxonMobil, Energy EXXI is drilling a higher-risk, higher-impact prospect, Pendragon, with an estimated gross unrisked potential of over 40 million barrels. If successful, Pendragon would set up a second, much larger prospect, Merlin. Terms provide for Energy XXI to carry ExxonMobil on the first two wells, retaining a 50% working interest; thereafter, the JV partners participate on a heads-up basis.

Noting Energy XXI’s acquisition of shallow-water properties from Exxon in 2010, Magner said he “would not be surprised to see them do more acquisitions. It’s part of the fabric of the company. They’ve had good success acquiring good assets and being able to do more with them. I still think that they have a lot to do on the Exxon properties that they purchased.”

Meanwhile, the shallow-water, ultra-deep program has been a “wait-and-see” story for far longer than expected—at one point the Davy Jones I exploratory well was expected to have a flowrate in early 2012. However, Energy XXI is also participating in the Blackbeard West well offshore, as well as both wells testing the onshore extensions of the play, the Lineham Creek and Lomond North wells. Energy XXI’s interests in the latter wells, drilling to TDs of 29,000 feet and 30,000 feet, respectively, are 9% and 18%.

While volatility in quarterly production numbers has been “a challenge for the story,” due to outages and third-party pipeline issues offshore, Magner still sees fiscal-year 2013 (ending June 30, 2013) volumes averaging 45,900 barrels equivalent per day, up 4.1% from prior-year levels.

One benefit from its offshore production is that about two-thirds is comprised of Heavy Louisiana Sweet, a grade that is expected to hold up better than Louisiana Light Sweet as growing U.S. crude production displaces imported light crude grades.

In terms of the company’s enterprise valueto-2013 EBITDA, Energy XXI trades at a 3.1x multiple and has about 22% upside to a price target of $41.

Gulf Coast prospects

Nick Pope, managing director with Dahlman Rose & Co., favors another Gulf Coast operator, EPL Oil & Gas Inc., New Orleans, because of its deep inventory of oil opportunities, strong capability to generate free cash flow, and disciplined acquire-and-exploit strategy. After a strong 2012 performance for EPL, Pope still sees attractive prospects for the company over the longer term in a robust oil environment. Oil accounted for about 70% of production at year-end 2012.

EPL’s latest foray on the acquisition front was the purchase of Hilcorp’s Gulf of Mexico shelf assets for $550 million in mid-2012. The deal translated to $55,000 per flowing barrel compared with $90,000 for EPL at the time. EPL has identified about 90 low-risk opportunities—typically either behind-pipe or proved undeveloped (PUD) locations—and these are expected to increase with new 3-D seismic and reprocessing. The former Hilcorp assets are expected to claim about $100 million of a total $300-million capex budget in 2013. Overall production is projected to be up over 70% following the acquisition.

Pope points to EPL management’s efforts in aggressively lowering costs and generating cash to bring down debt, as well as the fact that the company has underspent cash flow in each of the last few years.

“They really have done a great job of generating a lot of free cash flow, while also doing these ‘tack-on’ acquisitions that fit well into the company’s portfolio at fairly low costs. The discipline that they have been showing has turned into a real positive for them,” he says.

At $715 million, total debt is about 2.5x 2012 EBITDA—toward the high end of where EPL likes to be—but is closer to 1.5x on 2013 EBITDA. For 2013, Pope projects EPL will generate cash flow topping $430 million, allowing it to pay down some $120 million in debt after capex of $300 million.

Over $100 million of free cash generated by a company with an equity market capitalization of under $1 billion represents a greater-than-10% free-cash-flow yield in 2013, notes Pope.

“It’s a debt paydown story. In this oil environment, they’re letting that high oil price flow straight to the balance sheet,” observes Pope. And in a market in which investors are putting greater value on yields, it’s “pretty good option whenever you have a company generating over 10% free-cash-flow yield, even after the move that they have had.”

Pope likes management for its straightforward approach. “They’re solid operators. They’re keeping it very disciplined. They’re not trying to be anything they’re not. If you are positive on oil prices and the Gulf Coast, you’re seeing them reap the benefits. Plus, after the acquisition, production is up 70%.”

EPL has about 60% of its overall production hedged. Pope’s target on the stock is $24.