The spotlight doesn’t always shine as brightly on small-cap and midcap names—especially during down-turns. Analysts and investors tend to focus on companies of greater size that can command a larger audience. But some small- and midcap names are not only making it through the tough times; they are executing strategies to advance their corporate goals in spite of the downturn and commodity-price headwinds.

By no measure, however, are such companies always given full credit for their efforts. Conse¬quently, Investor asked analysts to identify E&P or oilfield service names that offer as-yet unrec¬ognized value, or whose fortunes are likely to improve once particular catalysts come into play.

Free option on the Delaware

Chad Mabry, senior research analyst at FBR Capital Markets & Co., points to Carrizo Oil & Gas Inc. (NASDAQ: CRZO) as one such exam¬ple. He rates the stock Outperform with a price target of $50, representing just over 45% upside from a close of $34.22 on Sept. 27. The stock’s market cap is around $2 billion, which some view as the line between small- and midcap names.

Wall Street is likely undervaluing Carrizo based on perceptions that its growth is less competitive than its peers’, and its projected capex will mean¬ingfully outstrip cash flow, according to Mabry. In addition, while some observers say Carrizo is “too spread out,” recent developments have been “over¬whelmingly positive” in the Delaware Basin and Niobrara Shale—two of the three areas that are outside its main area of activity, the Eagle Ford.

The Delaware Basin has hosted a flurry of transactions at elevated levels, which indicates “investors are arguably receiving a free option” on Carrizo’s position in “one of the hottest oil resource plays in the U.S,” he said. In arriving at a $50 target price, based on a net asset value (NAV) calculation, Mabry attributes zero value for Carrizo’s Delaware Wolfcamp play. The $50 NAV target reflects a valuation for only its proved reserves and upside potential in the Eagle Ford and Niobrara—but nothing for its Delaware, Utica/Point Pleasant and Marcellus holdings.

What could Carrizo’s Delaware position be worth?

The most recent, and relevant, Delaware Basin deal was PDC Energy Co.’s approxi¬mate $1.5 billion purchase of 57,000 net acres in Reeves and Culberson counties. Carrizo holds some 22,200 net acres in these counties, much of it close to PDC’s acreage—or, as Mabry describes it, “a direct overlay with Car¬rizo’s acreage.”

Adjusting for production and midstream, the PDC transaction implies a value of $22,000 per acre. Applied to Carrizo’s acreage, this trans¬lates into as much as $490 million, or more than $8 per share, potentially adding signifi-cantly to the company’s NAV, as “we have no upside for the play in our NAV at the moment,” Mabry said.

Carrizo is validating its position in the Delaware with some early well results. The company’s Liberator State 3H (100%) was brought back online and achieved a 30-day initial production (IP) rate of 1,400 bar¬rels of oil equivalent per day (boe/d). Its fourth operated well, the Corsair State 3H (100%), is still cleaning up, and “early results are encouraging,” according to the com¬pany. Estimated ultimate recoveries (EUR) are put at between 550,000 and 1 million boe (MMboe).

In total, Carrizo has identified 110 net undrilled locations on its acreage, representing over a decade of drilling with a single-rig pro¬gram targeting the Wolfcamp A.

The company’s initial development plan is focused on its most northerly block of 12,200 net acres that straddles the line between Cul¬berson and Reeves counties. Offset operators said to be reporting strong Wolfcamp A results include BHP Billiton Ltd., Cimarex Energy Co. and Energen Corp.

What are the prospects for growth from Car¬rizo’s 88,000 net Eagle Ford acres?

“No one’s going to try to argue the Eagle Ford as a whole is going to return to the pace of growth of several years ago,” acknowledged Mabry.

“But Carrizo has a high-quality, core posi¬tion offering decades of running room at some of the most compelling economics in the U.S. The company has identified over 1,000 net undrilled locations, of which more than 85% should have a breakeven price of $40 per barrel or lower.”

Carrizo’s initial guidance for 2017 puts oil growth at more than 10% to more than 30%, driven by either a two- or four-rig program, respectively, in the Eagle Ford. The two-rig program could be funded within operating cash flow at $60/bbl crude. Concern over the degree of cash flow outspend has eased as con¬sensus estimates for 2017 production and cash flow have risen, and management has issued constructive comments on capex, according to Mabry.

But asset sales present another path to growth in the event Carrizo were to receive an offer for its Delaware position at recent lofty levels, or, more likely, if it were to put its Niobrara assets up for sale. Proceeds would allow Carrizo to accelerate its drilling in the Eagle Ford or act as a consolidator, provid¬ing a growth strategy in a more mature basin, according to Mabry.

With two anti-energy ballot initiatives no longer clouding oil and gas development in Colorado, “I have a high degree of confidence they would be able to sell the Niobrara assets in short order,” he said.

Carrizo holds some 32,100 net acres in the oilier northeast extension of the play, which could comfortably fetch $14,000 per acre, or $450 million. This would equate to $7 to $8 per share, up from a $2 current value, he said. “Such a deal could be wildly accretive to our NAV for Carrizo.”

High-tech driller

Robert MacKenzie, director of research at Iberia Capital Partners, is quick to say Inde¬pendence Contract Drilling Inc. (NYSE: ICD) “is not for everyone,” given its sub-$200 mil¬lion market cap. The company has been public only since 2014, and on some days its trading volume is less than 100,000 shares. His target price for the stock is $7, 45% potential upside from a close of $4.81 on Sept. 27.

Why buy a land driller amid the depressed conditions prevailing in the oilfield sector?

Independence earns an Outperform rat¬ing on at least two counts. First, its fleet is composed of rigs designed with leading-edge equipment—typically 1,500 horsepower, AC-drive rigs with walking systems for pad drilling and, in most cases, 7,500 psi mud pumps needed to drill longer laterals. Second, not only is demand for its rigs rising, but most of its fleet is already working.

“Independence is a well-run, upstart com¬pany with ultra-modern, high-spec land rigs that are in reasonable demand,” said MacKenzie. “They currently have eight of their 14 rigs drilling, which is a much higher utilization than the industry as a whole. My understanding is that one of the two addi¬tional rigs currently on standby rates is in the process of being reactivated for work. Only a handful of rigs have to be reactivated for its fleet to be fully utilized.”

The company’s customer base tends to have drilling programs in some of the more active basins. Of eight rigs currently working, six are in the Permian. Energen and privately held Silver Hill Energy Partners LLC each have two rigs working in the basin, while Parsley Energy Inc. and Pioneer Natural Resources Co. each have one. In the Haynesville, where longer laterals and markedly higher proppant loadings have breathed new life into the play, private E&P GeoSouthern Energy Corp. has two rigs at work.

“One of the most sought-after specifica¬tions for a land rig today is an upgraded mud-pump system, specifically a mud system that can handle 7,500 psi,” said MacKenzie, formerly an engineer with Schlumberger. “Why that’s important is that it helps drill those longer, 10,000-foot laterals faster and with minimal problems. The greater pumping pressure enables you to clean out cuttings in a longer hole more effectively than older 5,000 psi systems, which are now stretched to their capacity.”

Industrywide, there are only about 200 to 250 rigs with 7,500 psi mud systems, MacK¬enzie estimated. With eight of its 14 rigs equipped with such mud systems, and all but one of the 14 “full walking rigs,” the company is “well-positioned for what E&Ps are looking for,” he said. “The one thing that ICD does not have is a bunch of older legacy rigs weighing it down, like its bigger competitors have.”

At $20.5 million, debt is not an issue, said MacKenzie. Building a new rig costs about $22 million, he noted, so the company is car¬rying “one rig’s worth of debt, while the other 13 rigs are unencumbered.” On another mea¬sure, with current year EBITDA projected at roughly $17 million, the debt/EBITDA ratio is about 1.2x.

Recent day rates for top rigs with upgraded mud systems are currently around $15,000 to $16,500, as compared to operating costs of about $12,500 a day, according to MacKenzie. Independence has four legacy contracts struck at higher rates, and these extend through late 2017-early 2018 for all but one rig, for which the contract rolls over early next year, he noted. Near-term, if crude prices increase to over $50, MacKenzie estimated pricing would likely rise by “maybe $1,000 a day.”

Independence plans “to kick-start growth by getting some rigs out—if necessary on a spec basis—to meet market needs ahead of the next cycle,” said MacKenzie. This strategy is projected to begin midway through or in late 2017, by which time all its rigs are expected to have been reactivated, with the exception of its oldest vintage rig. “At that point, with contracts on all or almost all of its rigs, the company can start thinking about building new rigs,” he observed.

MacKenzie’s target price of $7 represents 1x book value but only about 65% of the fleet’s net replacement value, assuming no further newbuilds. If, later in an upcycle, valu¬ations were to trade in line with a replacement value of $22 million per rig, his target would rise by $2. Meanwhile, second-half 2016 earn¬ings are likely to be “choppy,” he said, due to start-up costs such as additional crew costs and mobilizing rigs.

But with Independence “having gone from four active rigs in early August to eight in late September,” he noted, “that’s a high-grade problem to have.”

Under the radar

Mike Kelly, head of E&P research with Seaport Global Securities, is focused on two companies that are “under the radar” and share a theme. The E&Ps—Jones Energy Inc. and Ring Energy Inc.—are both putting rigs to work in less delineated areas between known plays.

Kelly assigns a $3.50 target price for Jones (NYSE: JONE), offering 24% upside from its close of $2.82 on Sept. 27, following the company’s recent acquisition of 18,000 net acres in the Anadarko Basin. The target price is based on an NAV using long-term oil and natural gas prices of $55/bbl and $3/Mcf, respectively.

“The recent acquisition is roughly in between the Stack and the Scoop plays,” noted Kelly. “They got in at a relatively cheap price of just under $8,000 per acre. While the reservoir includes a thinner Woodward and thinner Meramec, Jones and private operators affirm that this is more than offset by the very high quality of the rock in terms of porosity, brittleness and organic content. Everything checks out.”

The play is akin to an extension of the Stack, according to Kelly, with offset operators’ 30-day IP rates coming in at more than 1,000 boe/d. Wells produce from the Woodford and the Upper and Lower Syca¬more, the latter being equivalent intervals to the Meramec and Osage. With some small improvements, Kelly is optimistic about rais¬ing his NAV target for Jones.

“If the company continues to make improvements—for example, a 10% bump to Jones’ 890,000 boe EUR type curve, a drop in well costs to $3.5 million from currently $4 million and downspacing that increases inven¬tory from 12 wells per section to 22 wells per section on the existing 18,000 net acres—then we could see our NAV-based price target go to $6 per share from the current $3.50 relatively quickly,” he said.

There could be other catalysts as well. “We think Continental Resources is going to start drilling wells around the play, which should be taken as a real positive read-through for Jones,” said Kelly. Also, a possible sale of assets held by an offset operator that has suc¬ceeded in identifying the optimal landing zone and completion techniques could spotlight the value of Jones’ acreage, he added.

While debt metrics of roughly 4x 2017 EBITDA aren’t low, “if the wells are as good as others in the Stack, in a mid-$40s to $50 world it will be a de-leveraging situation and the credit metrics will improve naturally,” said Kelly. Also, the stock price factors in moderately higher debt, trading at a “cheap” multiple of just 6.7x enterprise value-to-2017 EBITDA, he said.

Kelly’s other favorite name, Ring Energy (NYSE MKT: REI), is drilling in the Central Basin Platform between the better-known Midland and Delaware basins. Kelly’s target price is $12, representing over 17% upside from a closing price of $10.20 on Sept. 27.

“REI is bringing horizontal drilling to the Central Basin Platform, with wells to the shallow San Andres Formation typically cost¬ing just $2 million and generating EURs of 400,000 barrels, almost entirely oil,” he said. “On an IRR basis, they offer the highest pro¬jected returns in the Permian and, by exten¬sion, the Lower 48.”

Confirmation of the results being “as good as advertised” should be available by year-end, he noted. Ring has drilled three horizon¬tal wells to date and, in late September, was completing the first of these. “For a micro-cap like Ring to have an inventory of 270 well locations to drill is absolutely huge.”

Assuming success, Ring is expected to be “the highest production growth com¬pany through 2020, achieving debt-adjusted growth of 45% per year from 2016 to 2020,” said Kelly. This growth is partially reflected in a lofty, 25x multiple of enterprise-to-2016 EBITDA, but this multiple drops to just 3.1x on projected 2020 EBITDA, he said.

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