Good news keeps flowing out of the Utica, at least operationally. In mid-January, Consol Energy Inc. completed its second deep, dry gas test of the Utica/Point Pleasant Shale in Greene County, Pennsylvania. The GH-9 well roared online at nearly 62 million cubic feet per day (MMcf/d) over its initial 24-hour reporting period, on a 6,100-foot lateral with a 30-stage completion. That well followed the Canonsburg-based company’s Gaut-4IH completion in Westmoreland County, Pennsylvania, reported in third-quarter 2015, with an initial flow rate of 61.4 MMcf/d. The Gaut-41H produced 1.26 billion cubic feet (Bcf) of gas in its first 60 days.

Following the drilling of these two wells, Consol dismissed all operated rigs at the end of the third quarter. To help achieve the lower end of its $200 million to $325 million budget guidance, a nearly 50% downward revision, it plans no new operated drilling for 2016.

Such is the dilemma in the Utica.

Operators in the play are pinched by monster wells with monster costs, liquids-rich wells deflated by NGL realizations, and by a painfully low Henry Hub natural gas price exacerbated by basis differentials. With cash flows challenged for even the best-situated operators, the choice is whether to drill or not drill.

The Utica rig count at the end of January stood at just 12, as reported by Baker Hughes, a 75% year-over-year decline from 47. The trend mirrors every other U.S. basin stressed by low commodity prices, with Henry Hub lingering near $2/Mcf. Yet basis differentials related to takeaway constraints push realizations in the gassy Utica below $1/Mcf in some hubs.

Every operator has hit the brakes hard. In November, Eclipse Resources Inc., like Consol, shut down its drilling program at least through the first quarter of this year. Stone Energy likewise went to zero in the Utica, as has Noble Energy Inc.

Rice Energy Inc., Rex Energy Corp., Statoil, Hess Corp. and Chesapeake Energy Corp. are maintaining one-rig programs. Only Antero Resources Corp., Gulfport Energy Corp. and XTO Energy Inc. are operating more rigs, at three, two and two, respectively, per Baker Hughes. EQT Corp. and Range Resources Corp. appear to be moving a rig into and out of the play selectively from their Marcellus programs.

The decisions have nothing to do with the resource, and everything to do with the return. In many cases, drilling in the play is cash destructive. Can Utica operators drill economic wells today?

Liquids poor

“At this price level, nothing in the Northeast is economic,” said Matt Portillo, managing director and head of E&P research for Tudor, Pickering, Holt & Co. “Given that we see marginal returns and in some cases negative returns on capital for wells being drilled today, that is a value destructive proposition, in our view.”

Neal Dingmann, managing director, equity research, for SunTrust Robinson Humphrey, with a host of Utica names under coverage, sees Utica economics as “right on the fringes” at today’s prices. “For your lean operators in the better dry gas areas, I think you can drill economic wells,” he said. He cited operators like Rice and Gulfport with well breakeven costs around $1.75, “albeit the return would be pretty slim, given we’re not far above $2.”

Liquids-rich wells, however, are underwater in each analyst’s view. The Ohio condensate window that was a popular target for early operators in the play at $100 oil has lost the most favor. With crude now trading in the low $30s, “those are by far the least economic wells in the basin, and you can argue they will generate a negative return on investment,” said Portillo.

“The condensate window has all but shut down from a drilling perspective. There’s really no activity left in that phase of the play.”

Similarly, wet gas wells fail to deliver positive returns, with ethane and propane accounting for some 80% of the NGL barrel, and neither in the money. Ethane is being rejected back into the gas stream, and the uplift barely covers transportation costs. Propane is a negative revenue generator due to elevated transportation costs on barges and trucks because of lack of pipeline capacity.

“The majority of the NGL barrel is negative, in our view,” Portillo said. “We would argue that the liquids-rich economics in the Utica would need to see a $3.50 to $4 gas price to make those returns work at strip pricing for oil and NGLs.”

Wet vs. dry

The Utica is experiencing a dramatic shift as a result of commodity price pressures. As NGL and condensate prices have cratered, operators have migrated eastward into the dry gas window, even crossing the state line into Pennsylvania where the play is deep and high pressured.

“Dry gas well rates certainly come on much better than wet gas wells,” given there are no processing costs, said Dingmann.

These wells’ decline rates—or lack thereof—make them unique. Extremely high subsurface pressure combined with wellhead choke management has resulted in flow rates that exhibit no falloff in the first months of production history, he said. “A lot of these Utica wells do not deplete for the first 12 to sometimes 16 months. That’s unheard of in this industry.”

In addition to the aforementioned Consol wells, the biggest wells so far have been drilled in Pennsylvania by EQT and Range Resources, with an EQT test briefly topping a 100 MMcf/d flow rate. “We’d never seen a well like that onshore in the U.S. It’s tough to handicap if you want to put an EUR on that,” Dingmann said. He suggests 20 Bcf-plus as a reasonable guess.

But the massive rates come at a cost. Reported well costs of $15- to $16 million for the deeper Pennsylvania Utica are prohibitive economically, compared with dry gas wells in eastern Ohio closer to $8.5 million.

“It’s an issue of if they can bring costs down,” Dingmann said. “The deeper wells in Pennsylvania are going to be larger wells, but on an economic basis I still don’t believe today there are better gas wells in the U.S. than those in eastern Ohio.”

Short of a material improvement in the oil price—say to $50 to $60—Portillo expects the majority of Utica rigs to focus on dry gas.

“The Utica boasts good, but not overwhelmingly great, well economics,” he said. “Dry gas is the most economic, but it’s still underwater at the current gas price this year. While highly prolific, the wells are still at a relatively high cost to drill.”

He projected gas would need to reach $2.50 to $3 to make a 10% return.

Dry gas Utica wells are also economically challenged when measured against like Marcellus wells, he said. Per thousand foot of lateral length, best-case recoveries in both plays average 2.5 to 3 Bcf.

“Even if we assume companies are able to access Henry Hub markets and receive higher realizations, breakevens for a $16 million, 2.5 Bcfe per 1,000-foot lateral type curve dry gas Utica well are approximately $2.75 per Mcf on a 9,000-foot lateral, still putting economics behind core Marcellus at $2 to $2.50 per Mcf breakevens.”

The key difference is the shallower Marcellus is about half the cost of the Utica to drill and complete. “The Marcellus is still vastly more economic on a like-for-like basis than the dry gas Utica at this point. We think operators will focus most, if not all, of their capital on the Marcellus,” Dingmann said.

EQT is an example of a Northeast producer with access to best-case pricing. Still, the company has guided a 44% capex haircut with most of its 2016 program aimed at the Marcellus. Nonetheless, it plans at least five deep, dry gas Utica wells in the year, with another five possible.

Dingmann, however, favors dry gas Utica economics over Marcellus. Reports from Antero Resources suggesting pre-tax NPV-10 single-well economics of $6.4 million for dry gas Utica, vs. $0.2 million for dry Marcellus, a 26% pre-tax rate of return, compared with 11%.

“We would suggest that most dry gas Utica wells in eastern Ohio currently generate a higher pre-tax NPV-10 or pre-tax rate of return than most dry gas Marcellus wells. The better Utica results are likely attributed to the slightly higher IP and higher estimated EUR despite the slightly higher estimated well and transportation expenses,” Dingmann said.

The capex call

If the rig count is an indicator of capex, expect Utica investments to be down this year some 70% from the peak in 2014 as operators make dramatic cuts across the board. But companies will resist laying down all rigs to avoid mature production decline.

“Even in a low price environment, investors want them to run at least a couple of rigs that will have a minimal amount of cash flow outspend,” said Dingmann. “The motivation is to spend as close as you can within cash flow.”

Holding acreage is another motivator. “You want to hold the leases. It’s a balancing act to hold onto better acreage and not outspend too terribly much.”

Gulfport, one of the better-positioned companies from a balance sheet perspective, dropped from 10 rigs at its peak to two anticipated in 2016, just enough to hold acreage, per Dingmann. It also suspended many completions in the first quarter and temporarily curtailed 100 MMcf/d in production.

“Even the likes of Gulfport, which has very little debt, is running the minimum just so as to not have to run up any excess capex at this time.”

Notably, in Gulfport’s November conference call, CEO Mike Moore indicated, “We are OK paying [acreage] renewals instead of drilling.”

Equity research firm Tudor, Pickering, Holt & Co., using data from the Ohio Department of Natural Resources, examined results within the state to determine Utica EURs across the various phases.

Portillo projected a “precipitous drop-off in spending in the Northeast” this year, which should begin to correct oversupply in the local market. Yet he believes more companies taking rig counts to zero and minimizing capex as much as they can is a real possibility.

“We’re getting to a point where this is potentially a very realistic outcome given the financial distress in the industry and the very, very weak returns on incremental capital for operators in the basin today. EQT shows a clear bias to ease up on the gas pedal, but we think Eclipse’s strategy of slamming on the brakes is the ideal strategy.”

Operationally, Eclipse, not covered by Tu­dor, Pickering, Holt & Co., had a good year in 2015: It reduced average drilling times by 50% while extending laterals 20%. It exceeded production guidance with the early addition of seven dry gas Utica wells in Monroe County in the fourth quarter.

Yet “limited liquidity and razor-thin cash margins—at best,” prompted the company to lay down all rigs and curtail production for the near term, Portillo said. “Eclipse’s update is a potential preview of sobering outlooks to emerge from Northeast operators in this challenging environment.” With all-in cash costs in the neighborhood of $1.30 to $2 and higher, “no one is generating a cash-on-cash return in the current environment.”

To that end, Tudor, Pickering, Holt & Co. has published a report stating that virtually every company under its coverage would be better off cutting capex to zero and buying back its own debt. “A lot of these bonds are trading at 30 to 40 cents off of par, and that’s a much better return than actually drilling an incremental well today,” the report said.

Consolidation barometer

Although the Utica is held by relatively few operators, Dingmann foresees assets changing hands as a result of operators with stressed balance sheets looking to raise capital. “You have willing sellers,” he said.

Specifically, he points to Consol, which has stated “anything and everything” will be considered for sale, with as many as 25 packages on the market. Chesapeake is in the market to sell some or all of its Utica holdings, about 1 million acres that Dingmann values at $4 billion, or $200- to $300 million for just the dry gas Utica, by Portillo’s estimation. Privately held Ascent Resources LLC, a combination of the American Energy Partners’ Appalachian divisions, is reportedly shopping acreage, too.

Buyers, Dingmann said, might include a host of private companies looking to get a toehold in the play, or even XTO, the resource play arm of ExxonMobil, which might like to bolster its position after selling down previously.

Only two recent public deals are available as benchmarks, both acquisitions by Gulfport: the purchases of Paloma Partners for $12,500 per acre, and Ascent Resources for $9,500 per acre.

“I believe the core of the Utica, the best part in eastern Ohio, is still garnering over $9,000 an acre,” Dingmann said.

Portillo also thinks mergers are in the offing, motivated by firm transportation commitments of both the haves and have-nots. While some operators might struggle to fill firm commitments in the current commodity price environment, distressed operators that are hamstrung by local spot prices are ripe targets.

“A&D may be the solution. Consolidation of operators that don’t have firm transportation commitments and are producing their gas locally in the basin, selling out to someone with firm transportation but that may not want to drill into that, is both healthy for the local basis as well as the operator acquiring assets.

“Take that extra production [from an acquisition] and put it into your own pipe. That way you don’t have to drill, you don’t have to spend capex, but you can maximize the value by the uplift on the realization you get on that production base.”

Portillo identified Chesapeake and Consol as Utica acreage holders most likely to tap the A&D marketplace to raise cash, with Magnum Hunter Resources Corp. already in the bankruptcy process with Ohio and West Virginia Utica assets. On the flip side, EQT and Gulfport sport bulletproof balance sheets—both with leverage ratios below 3x—with the most flexibility.

Looking ahead

The near-term fate of the Utica—i.e. capital investments—is predicated on the winds of natural gas pricing, said Dingmann. If prices stay in the low $2, rigs will remain sparse this year. But it wouldn’t take much upward movement in gas prices for the prognosis to change dramatically.

“There’s a material difference in returns between $2.15 today and Henry Hub at $2.50,” he said. “And there’s a big step up between $2.50 and $3. The closer we get to $2.50, the more activity we’ll see in the play.”

Good news: Portillo projects a material jump in natural gas prices by year-end.

“We see 2 Bcf of new demand with 2 Bcf of decreasing supply that should cause a sharp correction. By the fourth quarter, the market should balance and, by early 2017, assuming normal weather, we should see a $3.25 to $3.50 per Mcf Henry Hub price.” That same bump will capture investors’ attention as well.

The Utica “is certainly one of the top three plays,” Dingmann said. “We believe there’s value in this play much like we see value in the Permian and Stack plays. It can generate returns and value even at these low commodity prices. Bottom line: It can still compete for capital.”

Portillo also suggested Wall Street is “kind of very interested” in Utica players at the moment, with investors paying close attention to slowed growth coupled with aligning cash flow to capex.

“If you see operators cut back on their growth rate to maximize cash flow with better realizations, that’s a more favorable outcome for investors. Capital discipline is paramount. That’s when you’re going to see a lot more capital flow into the sector from an equity perspective.

“Growth is no longer a focus, and that’s a good thing.”

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