With sentiment toward energy at rock-bottom levels in late July, the SIG Oil Exploration & Production Index, commonly called the E&P Index, was plumbing depths last seen as the economy came out of the Great Financial Crisis in July 2009. You know it’s ugly in energy when the E&P Index falls roughly 25% in the seven weeks following the end of May and loses a startling 16% of its value in just nine trading sessions in July.

As you would expect, the generalist investor long ago abandoned energy, and professionals left to assess the outlook acknowledge a variety of headwinds. Not least is a rapid rise in OPEC crude volumes in a war for market share that has weighed on forward oil price projections. Along with perennial questions as to the strength of Chinese demand, this has pushed out the likely timeline for a potential rebalancing of oil demand and supply, which is increasingly a moving target.

But amid such a downturn lies opportunity. And all the more so in the small- and mid-cap energy subsector, which has been harder hit than its large-cap peer group. Now that the stocks are down hard—and hopefully will prove to be “cheap,” too, if commodity price decks pan out—which E&Ps do energy analysts favor for their staying power and upside potential in a difficult energy tape?

A pure play with legs

While energy negatives prevent Raymond James & Associates from assigning its highest rating to E&P stocks in general, managing director John Freeman is clearly enthused by Memorial Resource Development Corp. (NASDAQ: MRD). Freeman gives the prolific, gas-levered producer an Outperform rating and a $25 target price, offering 60% upside potential from a late-July level.

Memorial is a “pure play” operator in Terryville Field in north Louisiana and stands out from other E&Ps on several metrics, according to Freeman.

Growing at a compound annual rate of 57% per annum over 2014-2016, or almost twice that of its closest peer, the company “has the highest debt-adjusted growth rate the industry has seen in quite some time,” he said. And with a score of wells with 30-day initial production (IP) rates of 20- to 30 million cubic feet equivalent per day (MMcfe/d), Memorial “has the highest-return wells in the country.”

Memorial’s wells tap into four zones: the Upper and Lower Red, as well as the Lower Deep Pink and Upper Deep Pink. The main productive interval is the Upper Red zone, which even at commodity prices as low as $50 per barrel (bbl) and $2.50 per thousand cubic feet (Mcf) can generate internal rates of return (IRRs) that are “north of 100%,” said Freeman.

This assumes an Upper Red zone well costing $11.8 million, with an estimated ultimate recovery (EUR) of 20 billion cubic feet equivalent (Bcfe) and a net revenue interest of 78%. At Memorial management’s recent assumptions of $60/bbl and $3/Mcf, the well is projected to generate an IRR exceeding 200%.

With wells this prolific, coupled with a hedging program extending into 2018, it’s not hard for the company to maintain a strong balance sheet.

“The balance sheet is obviously great, because the wells pay out so quickly,” said Freeman. “And the hedge book is phenomenal, with substantial volumes hedged at attractive prices extending into 2018.”

For this year, Memorial has more than 75% of its estimated production of 325 to 365 MMcfe/d hedged at an average weighted price of about $4.88/Mcf. For the following three years, the company has hedges in place for a similar or larger absolute volume at weighted average prices of $4.41, $4.28 and $4.19/Mcf for 2016, 2017 and 2018, respectively.

So, with Memorial better positioned than most E&Ps to withstand the downturn, what’s not to like?

Investors became wary of what they thought could be the limited extent of the play following results that were unusually weak from a step-out well in the southern portion of Memorial’s acreage. The step-out, called LA Methodist Orphanage, or the LMO well, was drilled at a somewhat aggressive distance from the company’s prior wells to the north. The LMO well produced at a disappointing 30-day rate of just 3.7 MMcfe/d, raising questions about the prospectivity of the southern acreage.

“The debate focuses on the acreage footprint, with the bears arguing that Memorial has drilled the best acreage in the north, and the rest of the acreage is not going to prove prospective,” observed Freeman. “And for a company with a market cap of around $3 billion, Memorial wouldn’t have enough running room if the majority of the acreage to the south doesn’t work.”

Obviously, Freeman argues against this interpretation. But no argument will work better than if positive well results are confirmed during a heavy drilling schedule in the back half of this year.

Some 40-plus wells are scheduled to be drilled in second-half 2015, including 10 to 11 Lower Red wells and one Upper Deep Pink test. This compares with fewer than 10 wells in the first half. Freeman’s model calls for third-quarter production to jump to 37.6 MMcfe/d, up 74% from the second quarter, and to climb to 44 MMcfe/d in the final quarter of this year.

A key data point will be a Dowling well located roughly 1.5 miles northwest of the LMO step-out, which will provide the best indication of whether the LMO was a one-off disappointment or more indicative of the southern acreage’s prospectivity. In the interim, Memorial was expected to have results from the Aulds well, testing the play’s limits to the east and southeast, in its second-quarter earnings call.

“The Memorial story comes down to well results at this point,” said Freeman, noting the company’s strategy now lies in more measured stepouts from its core acreage than with the LMO well.

Using Nymex natural gas price assumptions of $2.80, $3.55 and $3.75 for 2015, 2016 and 2017-2020, respectively, Freeman calculates a net asset value (NAV) of $24.92/share for Memorial. This gives credit to identified Upper Red locations and some Lower Red locations, but nothing to Lower and Upper Deep Pink zones. Freeman applies a haircut of almost 50% to those Upper Red locations that fall into the probable and possible categories.

But more simply, said Freeman, “if you have an E&P that has the highest debt-adjusted production growth in the sector, and you can buy it at an Ebitda multiple that is in line or at a slight discount to the E&P group, that’s an opportunity that you don’t typically see.”

Permian favorite

Another name favored by Freeman is RSP Permian Inc. (NYSE: RSPP). Like several of its peers in the Permian, RSP has held up better than many E&Ps in other basins, which Freeman attributes in part to being in the “perfect zip code.” The company’s acreage, located in the heart of the Midland Basin, is comprised mainly of two consolidated packages overlying the Permian’s multistacked pays.

Freeman cited several factors supporting an Outperform rating and a $35 target price, representing about 40% upside. RSP combines some of the highest cash margins, running at 59% in the first quarter, with top-tier drillbit finding and development (F&D) costs, at $10.59/bbl, he said. In addition, it has grown production on a debt-adjusted basis by close to 25% per annum over 2014-2016.

RSP has targeted the Wolfcamp A and B zones, as well as the Lower and Middle Spraberry, on its Midland acreage. The company has tested at least seven combinations of multizone, multiwell pad development, with continued improvement in results. At 665,000 barrels of oil equivalent (boe), EURs cited by RSP are “far more conservative” than those of its peers, whose EURs are estimated at 800,000 to 1 MMboe, said Freeman, who anticipates RSP will revise its EURs upward.

In addition, the company has a “terrific balance sheet,” enabling RSP to be active in opportunistic acreage acquisitions. Whereas debt held by Midland E&Ps was generally close to to 3.5 times Ebitda, RSP’s debt-to-Ebitda on an annualized basis at the end of the first quarter stood at 1.6 times, almost half the level of its peers, noted Freeman.

RSP currently has an inventory of more than 2,000 horizontal locations. This is enough to last 15 years at today’s pace, but offers a shorter runway if market conditions allow RSP to increase activity from its current four-rig program and accelerate the present value of its inventory. “They do need more acreage. They’re constantly looking at different deals,” Freeman said.

Hedged to the hilt

At RBC Capital Markets, analyst Scott Hanold likes EP Energy Corp. (NYSE: EPE), another E&P that is increasingly focusing on its Permian assets. According to Hanold, EP Energy represents a “deep value” opportunity, where investors have been slow to give credit for asset quality and inventory, especially as related to advances in Permian well productivity. His target price is $17, potentially a double.

Currently, the Eagle Ford is EP Energy’s chief area of operations, with the Permian poised to rapidly narrow the gap in terms of rates of return and growth potential. Other operations are in the Altamont (Uinta) Basin and the Haynesville Shale. The company has recently transitioned from a production mix that was more than 70% natural gas to one comprised of 70% crude and NGLs in the second quarter.

The Eagle Ford remains the company’s “franchise” asset, accounting for 60% of second-quarter capex and breaking even at “just below $40/bbl,” assuming a required 10% pre-tax IRR, according to Hanold. In addition, the company is positioned as a “natural consolidator” in the Eagle Ford and, with its second-quarter results, announced a $118 million bolt-on acquisition of assets from Goodrich Petroleum.

The purchase involved some 12,000 net acres and 2,200 boe/d of production and represented an “attractive value,” said Hanold. With 164 potential drilling locations, the transaction will add an extra 1.5 years of drilling inventory in the Eagle Ford. This will strengthen the company’s position, he observed, in that the pre-acquisition, six-year inventory raised questions with some investors as to visibility beyond the company’s key Eagle Ford play. And this, in turn, focused attention on the need for success in the Permian as another avenue of growth.

EP Energy’s progress to date in the southern Midland portion of the Permian has certainly deserved greater recognition than it has been afforded, according to Hanold.

“Our model indicates that, with recent performance and costs, breakeven economics are $40 to 45/bbl. This is very competitive with other core parts of the Permian,” he said. “EP Energy is in an area where you’ve got a very thick section of oil, around 1,000 feet thick gross and 750 feet net. In addition, the company has done a lot science work and refinement of its drilling technique.”

EP Energy has said it will allocate funds from other programs to drill an additional 10 to 15 wells in the southern Midland Basin in the second half of this year. To date, the company has drilled 21 wells with a new drilling and completion design that on average are performing 40% above the company’s 450,000 boe type curve after 200 days. Hanold estimates that before year-end, EP Energy will announce an upward revision in the type curve, probably to a range of 500,000 to 600,000 boe.

In addition to the momentum in the southern Midland Basin, where EP Energy has some 3,300 drilling locations, Hanold said its “grade-A” management possesses impressive technical credentials. He forecasts the company will grow liquids volumes by 8.8% in 2016, following a 16% gain this year, and noted that cash operating costs have fallen steadily, resulting in cash margins of $40.75/bbl in the second quarter. The company expects to generate free cash flow for the balance of this year.

While EP Energy’s balance sheet carries relatively high leverage, at around 3 times Ebitda, its leverage hasn’t grown since the commodity price crash because of its remarkable hedge book, with an estimated value of about $900 million. On the oil side, it has 97% of estimated 2015 volumes hedged at $91.11/bbl and 79% of 2016 volumes hedged at $80.29. For natural gas, hedges of more than $4.20/Mcf cover 91% of 2015 volumes, dropping to 11% of volumes in 2016.

Hanold acknowledged that from a trading perspective, EP Energy is disadvanged in that it has a thin float. Long-term investors—typically private equity sponsors—own more than 80% of its stock. For an institution, “there is concern over trading liquidity. The float is thin. It will take time to build or exit a position,” he said.

In the event that commodities gain a footing and move higher, however, EP Energy should have more room to move than most. In setting price targets, usually at a 10% to 35% discount to E&Ps’ estimated pre-tax NAVs, the company’s $17 price target already reflects the steepest discount of 35%.

“There’s probably more NAV upside opportunity here,” Hanold commented.

Analyst Leo Mariani, also at RBC Capital Markets, sees Sanchez Energy Corp. (NYSE: SN) as a similarly undervalued opportunity. The company’s operations are focused primarily on the Eagle Ford, with a minor footprint in the Tuscaloosa Marine Shale. Mariani has an Outperform rating on the stock, with a $16 target, offering the potential for a double.

While Sanchez’s core Catarina assets in the Eagle Ford have shown plenty of progress, posting a 17% beat to second-quarter production guidance, the market has chosen to focus on the somewhat higher leverage carried on the company’s balance sheet, said Mariani. Such concerns are not uncommon with small-cap E&Ps, but in his view are overblown as regards Sanchez.

“Sanchez has seemingly been put in a bucket as if there is some kind of major financial risk here, and I really don’t think that’s accurate at all,” said Mariani. “The company’s got very strong financial liquidity, with $345 million in cash at the end of the first quarter and no bank debt at this point in time.

“They do have leverage that’s a little higher than you would like, but hopefully we’re near the bottom of the price cycle here. And they’ve got plenty of staying power such that, even if oil prices stay low for the next couple of years, there’s still no major risk of financial stress. In addition, they don’t have particularly high drilling obligations over the next few years.”

Sanchez acquired its Catarina acreage from Royal Dutch Shell in the spring of 2014, and Mariani is quick to acknowledge that much of the acreage has yet to be tested to establish its precise economics. In addition, the acquisition was made in a much higher commodity price environment.

That said, the purchase by Sanchez was based on its development of the Lower Eagle Ford, whereas Shell had already successfully tested the Upper Eagle Ford as well. And development was focused mainly on western Catarina, with central and eastern areas viewed largely as a blank sheet of paper, providing upside if they worked.

“They always thought that if there were success on the central and eastern areas, that would be gravy. They weren’t banking on that at the time of acquisition,” recalled Mariani. “And Shell had drilled almost everything in the Upper Eagle Ford, and Sanchez thought there was an opportunity in the Lower Eagle Ford that had not really been explored.”

Sanchez pre-announced second-quarter results, with production “materially above guidance,” Mariani said. “It certainly appears as though in the short term the wells are performing strongly.”

In the pre-announcement, Sanchez reported bringing on two three-well pads in southeastern/central Catarina, where they were performing in line with existing western Catarina wells. The two pads saw 24-hour IP rates of between 1,400 and 1,800 boe/d and were trending about the company’s 600,000 and 700,000 boe type curve. In addition, the eastern Catarina wells were showing less-than-expected declines.

In total, Sanchez brought online 35 gross and 31 net wells in the second quarter. Production totaled 53,920 boe/d, 17% ahead of guidance of 42,000 to 46,000 boe/d. However, production was slightly gassier, with liquids representing 69% of production, down from 72% in the prior quarter.

Sanchez also raised full-year 2015 guidance to 44,000 to 48,000 boe/d, up 5% from the previous midpoint. “We think that, given the company’s solid production results through the first half of 2015, this revised guidance appears conservative, and we see further upside from here,” commented Mariani.

With the market still “very skeptical” on Catarina, Mariani said he applied a “high risk factor” in his $16 target price, which reflects a 24% discount to its estimated pre-tax NAV.

“But to the extent Sanchez can de-risk the play over the next few years, the NAV has the potential to go up a lot,” he said.

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