Screening The E&P Equities

Following the tape can leave analysts and investors feeling a bit woozy, maybe even schizophrenic, these days. Strong oil prices and surging production are creating wonderful cash-flow metrics, some nice investment ideas and smiles all around.

But flip the switch to natural gas, and frown lines take over. According to the Energy Information Administration, the U.S. was oversupplied by an average of 1.3 billion cubic feet a day over the past three years. In 2011, domestic supply averaged 68.5 Bcf a day against demand of only 66.8 Bcf.

The macro picture also seems tough to call. China’s growth is slowing down, but it is importing more oil. Housing starts are inching up, but so are foreclosures. Then there is another factor that causes E&P stocks to trade at a discount—risk. Geopolitical risk weighing on E&P stocks presently is a wild card making it difficult for portfolio managers and clients to have a constructive thesis. When the market doesn’t know what level of confidence to have for prices, or equities in general, they are assigned a higher discount than normal.

How to play all this? We checked in with three stock gurus—David Deckelbaum, senior exploration and production analyst at KeyBanc Capital Markets; CLSA Asia-Pacific Markets E&P analyst Jeb Armstrong; and Andrew Cole-man, managing director of E&P research at Raymond James & Associates—to see what’s on their radar screens and how they are sorting through choices in the E&P universe.

The gas picture

KeyBanc’s Deckelbaum doesn’t think the gas picture is bleak—it just isn’t getting much better soon. Investors are more interested in liquids-driven companies, particularly those that can grow production.

“The world is still bearish on gas and struggling for a timeframe to see the light at the end of the tunnel,” he says. The general attitude toward gas equities is that there is a light at the end of the tunnel, but they are uninvestable right now.

At the same time, there is a perception that at $2.30 gas, the industry isn’t far away from the bottom and if conditions were to turn, natural gas equities would turn as well.

“But despite the fact that $2.30 gas isn’t going to $1, low prices could persist for some time. Stocks aren’t reflecting the harsh reality of $2.30, and the financial strain grows, the longer you have to live with that reality,” says Deckelbaum.

Some natural gas-weighted companies can make $2.30 into an economic endeavor, but generally those would be levered to the Marcellus shale. Deckelbaum suggests that if investors want to own dry-gas names, they should high-grade their choices based on assets that can make a return on investment through most commodity cycles. He concedes most gas-focused equities have longer-term investor appeal.

“Range Resources Corp. is in the best part of the best gas play: the Marcellus. And they have oil plays to look at,” says CSLA’s Armstrong. Range is a low-cost producer with a relatively strong balance sheet, excellent management and a good strategy. He would put it at the top of gas-levered players. But that is a short list.

“Particularly as we exit (gas storage) withdrawal season and go into shoulder season, with warmer-than-normal temps, we are really feeling the brunt of oversupply,” notes Deckelbaum. “And without a significant demand correction, we need to wait for a significant supply response from operators.”

The gas rig count is down, but as more companies turn their drillbits to oily plays, analysts see ample amounts of oil that also yield associated gas.

Armstrong agrees that some of the most gas-levered companies have been pursuing liquids opportunities. This group includes Quicksilver Resources, which has been investigating Colorado liquids plays and the Permian Basin. “Ultra Petroleum and Southwestern Energy are both are making liquids plays. Southwestern hasn’t had any luck, but it still has some things up its sleeves,” Armstrong says.

No E&P company expects to stand on gas alone, and some are scrambling. Even natural gas liquids, which have to some degree been propping up gas volumes, are starting to slacken, according to Armstrong. The basket of NGLs historically trades at 50% of the oil price. Due to increased NGL production, that price is slipping and is currently closer to 40% to 45% of the oil price.

In this environment, Raymond James’ Cole-man thinks capital discipline is required to withstand pain that could last throughout the second quarter. There is some optimism that natural gas production will decline, but not enough to change the picture in the short to medium term.

By summer, gas-levered E&Ps could see credit-facility reductions and ceiling-test impairments from drops in both the gas forward curve and the trailing 12-month average price used in reserves reporting to the SEC. Improved oil prices in 2010 and 2011 prevented major negative headlines in year-end reserves, however, and recent comments by service companies about falling frac prices point to a modestly improving margin outlook for E&Ps. This could represent a brief calm between the storms.

“Second-half 2011 gas prices averaged $3.90 per MMBtu. But a glut of gas storage, coupled with strong production growth, is biasing first-half 2012 towards $2.50 per MMBtu,” Cole-man says.

From an all-in cost perspective, the potential for asset impairments could provide a little cover starting in second-quarter 2012. Additionally, the potential for decelerating supply growth could create a pricing inflection point. Contrarian gas buyers still may need to see bankruptcies before recognizing a bottom in the market, however.

“Targeted gas names are still a contrarian pick,” Coleman says, pointing to the strength of oil in the short term as the market weighs the risk premium, the likelihood of war with Iran, and other macroeconomic data like housing starts.

Deckelbaum says gas stocks could start to get interesting at the end of the year, when it will be more evident how supply has been affected by the curtailment in gas drilling under way.

“It will be interesting to see if certain names that have said they would shut in (production) actually have, and how fast the curve responds to those fundamentals,” he says.

At that point, investors should be looking to see if $3 to $4 hedging demand comes into play, if there have been material revisions to borrowing bases, and where lenders’ price decks stand. “Banks are still using an overly conservative deck for oil and an aggressive deck on gas,” Deckelbaum says, pointing to an apparent bias for extending credit to gas-weighted companies.

Growth first

Oily names are in vogue, but with West Texas Intermediate crude above $100 and Brent trading even higher, it is hard to imagine E&P stocks as a value play. But Deckelbaum and his cohorts are looking for just that: companies whose stock does not reflect crude pricing at or above $100 per barrel.

The other growth metric they are watching is cash flow. A $10 increase in per-barrel pricing creates a significant difference in reinvestable cash flow, a factor Deckelbaum says investors do not fully appreciate for its ability to affect balance sheets and growth potential.

“The preference for most of these operators is to focus on growth potential. For investing, you want to look at names you think are growing, with growth as the priority, and returns exhibited secondarily. That’s going to impact what multiple I am willing to pay,” he says.

One of his favorites, Energy XXI, has shown rapid returns on investment from its initial efforts on the offshore properties it acquired last year from ExxonMobil.

“They are really just starting to dig into that inventory, so it’s early innings of an exploitation program,” he says. Companies with this kind of growth potential are very attractive. Energy XXI and Plains Exploration & Production are both free-cash positive and growing production 15% or more per year. Being free-cash positive is still a rarity for an industry that routinely outspends cash flow.

Plains is trading at 5.1 times 2013 EBIT-DAX, in line with a group of E&Ps that trades at an average of five times EBITDA and predominantly outspends cash flow. The company’s cash generation is underappreciated, and Deckelbaum thinks Denbury Resources is a similar story.

Raymond James’ Coleman agrees that production growth is taking the wheel and pushing pure pricing plays to the back seat. His bottom-up macro model indicates that the WTI oil price will be range-bound long term to $90 per barrel instead of $100-plus, owing to a significant increase in U.S. production.

The big picture the Raymond James team paints is of an incremental increase of 1 million barrels per day annually as oil-shale activity takes off. By putting together decline curves from all major plays, projected growth was even higher, at 1.5 million a day of incremental production, and was then scaled back by removing drilling efficiencies, tempering initial production rates, and steepening terminal decline rates.

“Modeling U.S. production is problematic without pressure data,” notes Coleman. “Assuming demand holds up, the bottleneck will be infrastructure, because it sure looks like the resources are there.” Still, the overall story is growth.

The Street looks at production growth per debt-adjusted share, to discern which company can generate growth without overly straining its balance sheet.

“If we don’t know where the incremental barrel will be priced, it’s about growing volume. Production is less constrained at the drill bit and more by infrastructure. It’s a true manufacturing thing now: exploitation instead of exploration,” says Coleman.

Companies getting more than WTI are guiding to Brent prices. “The reality is that instead of $100 to $110 realizations, they are seeing $110 to $120,” he says, an incremental gain making a huge impact on revenues and EBITDA margins.

Pricing is also driving momentum back into East Texas, where Anadarko Petroleum is in the Cotton Valley, along with PetroQuest, Forest Oil and a slew of others. The South Louisiana Wilcox play, in the shadow of the Tuscaloosa marine shale, is also gaining attention as pricing in the basin strengthens.

Costs second

Softness in the natural gas market has eased service costs to some extent in Texas and the Gulf Coast, says Deckelbaum. Drilling and completion costs aren’t main valuation drivers, but they are something analysts consider. Significant well-cost reduction can add meaningfully to returns. Coleman notes, however, that a 10% move in commodity price for a quarter has a much bigger impact than reducing costs.

In more secluded markets like the Bakken play in North Dakota, Deckelbaum sees a relative shortage of service availability persisting. That creates a bit of a return ceiling for investors until well costs decline meaningfully. Some wells in the Bakken have hit the $12-million mark, a 50% increase over early wells that came in at $8 million, although this increase stems as much from added frac stages as from frac-cost inflation.

In the Eagle Ford and Permian, Deckelbaum projects service costs will ease off the 2011 peak. He says most analysts are modeling well costs moderating over time. Companies that can materially reduce costs over their peers in their respective basins are drawing the interest of analysts and investors.

“That creates investor favoritism towards companies that have entered the ‘manufacturing stage’ and can take advantage of scale. Those companies are the ones that have worked well costs down a couple million less than their peers,” he says.

Continental Resources is Deckelbaum’s favorite company in that realm, although most Bakken companies are not materially differentiated from their peers on EBITDA multiples. Costs generally aren’t bleeding through into valuation on an acreage or NAV basis.

“To some extent, that speaks to the fact that investors are willing to assume well costs will improve over time. That gets back to the primary point that growth is still the priority,” he says.

CLSA’s Armstrong says each basin has low-cost leaders; he likes low-cost driller Whiting Petroleum in the Bakken and Concho Resources in the Permian. Armstrong, too, sees costs declining in some liquids basins. The overall rig count has plateaued in the last couple of months, stabilizing the pull on equipment, and pressure-pumping costs are moderating.

Coleman favors resource players that are Top Five acreage holders in established resource basins, such as Continental Resources or Den-bury Resources, with the potential to drive production and NAV growth. For cash-flow growth and catalysts, he favors Energy XXI. Anadarko offers large-cap exposure to world-class exploration plus Niobrara and Eagle Ford exposure. If gas exposure is desired, he’d look at QEP Resources, because its midstream infrastructure adds liquids upside. On the small-cap side, he is a fan of recently public Bonanza Creek Energy for its Niobrara acreage.

Corporate risk

Some investors are thematically choosing between integrateds or smaller, basin-specific companies based on perceived risk.

“Large-cap-focused people get nervous with small guys because they are relatively illiquid and more volatile. Unless you understand the plays, you don’t want to get involved with smaller names,” Armstrong says. Some small caps were hammered recently while larger-cap stocks held up relatively well.

But the cycle is coming back around, and Armstrong says investors are starting to nibble at the smaller names once again. Smaller names can be play-specific bets: he looks for best-in class operators like Whiting and Oasis in the Bakken and Noble Energy in the Niobrara. Cimarex is fairly well situated in the Permian, and has the ability to grow production because of its acreage position.

Deckelbaum says growth in production and revenue are even making investors indifferent to the choice between onshore and shallow offshore players. The decision comes down to which company has the most upside potential for what investors are paying today. Both cases have compelling points, and the shallow offshore does not have the regulatory risk exposure that deepwater still faces.

Armstrong thinks Bill Barrett Corp. has an interesting oil play in northeastern Utah. There are logistical issues to hammer out, and geological risk. The yellow wax or black wax crude the company produces can’t be piped because it congeals, so the logical destination for its production is Salt Lake City, which has five refineries.

“If you could get the high-quality oil with the right equipment to the right location, you could make a good margin, but there is not a ton of capacity,” he says.