To say it was a big day in the EQT corporate tower in downtown Pittsburgh would be an understatement. Watching monitors with real-time field information, virtually the entire complex waited with anticipation in late August for the Scotts Run well in Greene County, Pennsylvania, to come online and begin producing. The well, EQT’s first test of the high-pressured Utica dry gas phase in southwestern Pennsylvania, had been troublesome, costing some $30 million out of an abundance of caution. Earlier, Range Resources had success with a deep, dry Utica completion north of here in Washington County at 59 million cubic feet per day (MMcf/d) initial production, and indications during drilling and completing of Scotts Run pointed to a positive outcome. But the operations team needed the well to be amazing to hope for an economic outcome for their expensive experiment.

Then the gas came screaming through the meters into the system, in which other Marcellus production had been shut in to make pipeline capacity for this day. The well quickly spiked up to 110 MMcf/d, topping 9,500 psi, before being reined back into a range of 70 to 80 MMcf/d. For the first 24 hours on production, the operations team in Pittsburgh was unable to sleep, watching the monitors, questioning the field operators with every tweak of the valves that appeared via the screens, wondering if the well would retract.

Planned Northeast capacity additions will add north of 35 Bcf/d of potential takeaway for Marcellus-Utica producers.

It did not.

Scotts Run was choked back to 20 to 30 MMcf/d, where it has held flat since. Casing pressure remained above 7,000 psi. With an official 72.9 MMcf/d average 24-hour IP rate, the well is one of the largest onshore gas wells reported in history.

“The excitement running through the office was high,” said David Elkin, EQT senior vice president of drilling and completions. “There were emails and texts going out in the middle of the night; people were so excited they couldn’t sleep. They were waiting to see if it would fall off, but it just kept going.”

Scotts Run illustrates the potentially vast volume of natural gas poised to come out of the Northeast U.S. The Energy Information Administration estimates the Marcellus Shale holds a treasure trove of 141 trillion cubic feet (Tcf) of technically recoverable gas—others say as high as 500 Tcf—making it one of the largest gas fields in the world. The University of West Virginia in July published a report indicating the Utica Shale might hold 20 times the amount previously believed, or 782 Tcf of technically recoverable reserves. Together, these two plays alone could satisfy the natural gas needs of the U.S. for 45 years.

The Marcellus and Utica combined approached 20 billion cubic feet per day (Bcf/d) in September, per the EIA, accounting for a quarter of all U.S. gas production. The two plays comprise 85% of all shale gas growth since January 2012, the agency reported, with an increase of 12.6 Bcf/d, “making these regions the driving forces behind overall U.S. natural gas production growth.”

There’s just one problem with this success: The gas has to get to market, and thus the snag. Infrastructure build-out lags supply, creating pipeline bottlenecks and gaping price differentials to an already low Henry Hub price. Today, operator activity is slowing down, either to avoid selling product into a low-priced market, or simply because capacity is not available to move new production. The rig count in the two plays has dropped by 54% year-over-year.

But the takeaway constriction is temporary—three years at most—as a wave of proposed pipeline projects is set to phase in 42 Bcf/d of additional capacity by 2018. With reinforcements on the way, how are operators minding the gap, and once infrastructure catches up to supply, how will Appalachian gas impact the U.S. natural gas markets?

Since the beginning of 2012, the Marcellus and Utica regions have accounted for 85% of increases in production from the primary U.S. shale plays.

Near-term slowdown

After a tremendous run of an average 3 Bcf/d production growth over the past six years, analysts are predicting a slowing of Northeast gas growth—but not a decline—due to soft gas and gas liquids pricing. Morningstar analyst Jonathan Wolff, in a September report, said the anticipated slowdown is a result of weak local prices and pipeline bottlenecks.

“For 2016, we forecast Northeast supply growth of about 1.4 Bcf/d, with a fairly equal split between the Marcellus and Utica developments,” he said.

Analysts at Tudor, Pickering, Holt & Co., in a late September report, estimated Appalachian producers need higher than $2.75/Mcf to counter production declines while spending within cash flow, while still predicting basin growth in 2016, albeit decelerated.

“We see total Northeast gas volumes growing 2.2 to 2.4 Bcf/d next year with activity primarily driven by the Southwest Marcellus/ Utica as additional takeaway capacity comes online. Longer term, we believe that basin needs approximately $3/Mcf to hold production flat while spending within cash flow.”

Bernadette Johnson, managing partner with Denver-based analytics firm Ponderosa Advisors, told Oil and Gas Investor that the Marcellus-Utica combo is propping up an otherwise slumping nationwide gas production profile. While crude-associated gas production is declining with the fall in oil-directed rigs, she also projects Northeast volumes to continue to grow, holding U.S. production rates flat.

But the headwind is that Northeast producers are now experiencing negative basis differentials of $1.20 to $1.50 back from Henry Hub, exacerbated by nagging outbound pipeline bottlenecks. Considering Henry Hub was trading below $2.50/Mcf at press time, that leaves a buck and some change for produced gas—hardly motivating.

“These producers are realizing very low prices,” she said. “They can’t get the volumes out.”

No wonder many are pacing their development to match access to pipeline capacity: Some producers have bought into the projects themselves, and some are curtailing production in anticipation of better future pricing.

Chesapeake Energy Corp., for instance, squeezed back 100 MMcf/d from the Utica during 2015, waiting for Spectra’s OPEN pipeline, due online in November. Antero Resources is pushing 50 well completions into 2016 to achieve higher gas price realizations. In its first-quarter comments, midstream operator Williams Co. reported producers selling into its lines were holding back 300 to 500 MMcf/d in lieu of weak pricing. Stone Energy likewise pulled all capex from Appalachia, choosing to take an “investment intermission” and instead funnel its resources to the Gulf of Mexico.

“You need infrastructure to get a decent price, because you’ve got to get it out of the basin,” said Seneca Resources president Matt Cabell. “Therefore, some companies are curtailing until that infrastructure is in place.”

Like Antero, many operators, including Seneca, are drilling but holding back on completing wells, keeping them in inventory until takeaway capacity results in better pricing. Those price dynamics will begin to change as soon as capacity comes online, Johnson said, even as soon as year-end.

“We’re on the precipice right now,” she said, with an expected 2.5 Bcf/d of new capacity coming online by year-end 2015, headed primarily into Gulf Coast and Midwest markets. “As soon as those pipes come on, those wells will come online quickly, and we’ll see a jump in production.”

Longer term, as pipeline build-out outpaces supply growth, “then we definitely expect that basis to tighten up significantly, and those volumes to flow out of the region. Prices will get better when these pipes come online. As soon as those bottlenecks go away, everything will trade within variable,” which she expects to occur in the next 18 months.

And that can’t come too soon for Northeast operators.

Seneca’s strategy

Seneca Resources, the Houston-based E&P division of National Fuel Gas, is producing 370 MMcf/d now out of Pennsylvania, not coincidentally equal to its firm sales and firm transport capacity. “We’re capable of producing more,” said Cabell, “but we’re curtailing production that we feel we can’t get a fair price for.”

While natural gas prices are challenged “across the board,” he said, “they’re especially tough in Pennsylvania,” where he sees differentials regularly greater than a dollar to Henry Hub. “We’re not selling into the spot market—all the gas we’re selling we either have firm transport into a better market, or we’ve got a long-term firm sales contract at an acceptable price.”

With these firm contracts and associated hedges, Seneca receives an average of $3.50/Mcf, significantly better than the basin spot price. “If we’re getting $3.50, we’re in great shape,” Cabell said.

The Marcellus producer needs a realized price of $2.20—after transportation costs and basis differentials—to make a 15% IRR on full well-life economics, its breakeven.

Seneca is patiently waiting for the Niagara Expansion pipeline, a joint NFG/TGP project scheduled to be in-service this month, adding 170 MMcf/d, and the Northern Access pipeline, an NFG project, with a planned in-service date of late 2016, adding 490 MMcf/d capacity. Both of these projects will access the Dawn Hub in Ontario, Canada, which historically trades at a premium to Nymex. Further out, in late 2017, Seneca holds 190 MMcf/d firm contracted on Williams Cos.’ Atlantic Sunrise pipe, for a total of more than 900 MMcf/d in total capacity leading into 2018. “Everything we’re doing now in our drilling and completions is designed around filling that firm capacity when it comes on.”

Three Seneca rigs drilled approximately 75 wells in fiscal 2015 (ended Sept. 30), with two rigs going forward to drill 60 more in 2016. A single frack crew will keep a slower pace of completions until pipeline capacity is available, creating a backlog of wells, he said. Then, “we’ll get after completions quickly to fill that volume.”

Seneca concentrates its operations and rigs on 200,000 acres in its Western Development Area, in advance of coming takeaway capacity. Here, the rigs are drilling on a plot in Elk County known as Clermont/Rich Valley, in which the company has identified a fairway with 6 to 10 Bcf EUR per well. In all, it has some 860 locations economic between $2.20 and $2.45.

Historically, wells at CRV have averaged 7.7 MMcf/d at initial IP, with 6,000-foot laterals, and 5.8 MMcf/d over 30 days. However, tests on newer wells with up to 9,500-foot laterals flowed 8.5 to 10 MMcf/d on 24-hour rates. “They’re good, solid wells,” he said.

Seneca usually drills out all the wells on a six- to 15-well pad before breaking down the rig.

To drive cost efficiencies, the company created a centralized water system that recycles its own produced water along with third-party water to use in its well stimulations. “Total cost for our water is less than half what it was a couple of years ago,” Cabell said.

Further away from seeing new takeaway capacity, Seneca has pulled all rigs out of its Eastern Development Area in Lycoming and Tioga counties, its focus the past few years. Many of these wells came online at more than 20 MMcf/d, with EURs between 13 and 14 Bcf, with another 50 or so remaining to drill.

“It really is all about the takeaway capacity,” he said.

Once capacity arrives on the Atlantic Sunrise pipeline in 2017, upside includes both Utica and Geneseo potential. The company tested a Utica well in Tioga County at 22.7 MMcf/d, and a Geneseo well in Lycoming County at 14 MMcf/d. It anticipates drilling two Utica wells on its Clermont acreage in Elk County next year.

“From a Seneca perspective, we’ve got decades of potential drilling in multiple shale horizons. The Marcellus-Utica is growing because it’s the most economic gas play in the country. I don’t see any reason why that’s not going to continue. The future looks pretty bright for Seneca.”

Reversal of fortune

With gas processing infrastructure now ahead of supply, and with dry gas pipelines turning on over the past year, Northeast production areas heretofore stunted by lack of infrastructure are on the cusp of being on open choke.

“The Marcellus-Utica shales are the most economic areas to drill in the whole country,” said Johnson, “and they’re going to continue to be. We see a lot of producers with breakevens between $2 and $3. They won’t be held back as much going forward.”

The result is a paradigm shift for U.S. natural gas flows. Where 10 years ago gas flowed west to east to feed large population centers in Chicago, New York, Boston and the East Coast, the supply from the Marcellus and Utica is causing a polar shift.

“The way gas has flowed across the country is going to change,” said Johnson. “The Northeast is going to be a net exporter of gas, even during winter months of peak demand. Instead of moving east, everything is going to start moving west. We’re already seeing that happen, and we expect it to be year-round starting in the next couple of years.”

Traditional flows from Canada to the Northeast U.S. have all but stopped. REX, the Rockies Express pipeline built to move Rockies gas to the East Coast, reversed its easternmost segment and now moves volumes out of Appalachia back to the Midwest. Older pipelines, such as the Tennessee, Transco, TETCO and CGT, have announced backhaul projects or flow reversals, where instead of moving gas north, they now move it south as well, backward to the Midcontinent and Gulf Coast.

“All the major pipeline companies are having to adjust how they flow gas, and what old contracts look like and what to do when they roll off. End users, like utilities, have different options of how they source their gas. All of these things are having a ripple effect across the country.”

Incremental takeaway capacity will help to close the gap between Northeast price differentials and other nationwide benchmarks.

And the primary source of this near-future gas supply will be from the Marcellus-Utica region, she said, followed by associated gas from liquids-rich or oily drilling elsewhere. This shift in flows necessarily alters how some producers approach their gas marketing strategy.

End user in mind

Unlike producers who rely on future third-party infrastructure projects, EQT constructs its development plan alongside its sister company, EQM Midstream Partners. Blue Jenkins, executive vice president of commercial for EQT, is the common denominator, also overseeing business development for EQM’s pipeline build-out.

“We don’t feel constrained by our ability to grow,” Jenkins said of the company’s E&P strategy. “We’re thoughtful in timing our growth profile to match those new takeaway projects. The synergies are tremendous.”

With current production near 2 Bcf/d, EQT targets end users of its gas—such as local distribution companies (LDCs), power generators, and industrial users—to bypass basis differentials. Less than 20% of its production is sold at spot.

“We have a nice transportation portfolio that gets a large portion of our gas out of the basin,” said Jenkins. “That portfolio allows us to manage around some of that near-term risk. If you can get outside of the basin, the price is more like Nymex.”

EQM’s 36-mile Ohio Valley Connector pipeline, scheduled to come online in third-quarter 2016, connects to REX and will give EQT exposure to the Midwest market. The project adds 1 Bcf/d capacity, with 650 MMcf/d locked into a 20-year contract. The MLP’s Mountain Valley Pipeline, a 300-mile pipe due in service in fourth-quarter 2018, will deliver 2 Bcf/d of gas into the southeastern U.S., an underserved “market island” between the Northeast and Gulf Coast markets, per Jenkins.

“We have a portfolio approach that covers four geographic areas,” he said, the Northeast, Southeast, Midwest and Gulf Coast. “If we knew exactly where the market was going to go, we’d sell all our gas to that market. But because we think markets are dynamic and, over the long run, very efficient, there are near-term dislocations that we try to take advantage of.”

As part of that balanced strategy, expect EQT to participate in the growing power demand market—“that’s where we spend a bunch of our time”—as well as develop long-term relationships with LNG facilities. “We interface with that international market and the growth that comes there.”

The company also seeks to be a supplier to regional industrial projects. “We’re targeted on making solid relationships with people who use the product,” he said. “Strategically, we’re very balanced.”

Looking ahead, EQT’s Elkin said those two pipe projects will drive the company’s ability to grow, as the pace of drilling follows available infrastructure. “Those will impact our plans for 2016 and beyond. We need the capacity. Those will definitely help our situation.”

EQT’s drilling program has retracted only slightly, with a planned 180 wells through 2015 vs. 259 anticipated earlier. And the company intends to remain active, said Elkin; it’s just a matter of how active.

“As long as we feel like we’re making prudent investments, we’re going to continue with this year’s program,” he said. “It’s too early to say about next year, but we’re certainly drilling economic wells.”

Although coy on specifics, he added, “we’re comfortable with the returns we’re receiving from those wells.” The company is not holding back on completing the wells it drills either, he said, with only normal delays in bringing them online.

Elkin said most of EQT’s five big rigs (along with three tophole rigs) will concentrate on the Marcellus dry gas window in southwestern Pennsylvania, an area that is currently realizing the best economics in its portfolio, north of 20%. Even with NGL prices down, the wet gas area of its West Virginia holdings offers nearly equivalent economics to the dry phase there.

But realized prices would have to top $3.50/Mcf to move rigs back into its central Pennsylvania position, he said. “It’s close, and we do have a lot of acreage there. We’ll keep our eye on it.” No rigs are currently drilling Huron in Kentucky, once a featured play.

Meanwhile, EQT is trying to push technology in the area of air drilling, a technique it practiced in the Huron play. Now it is deploying the technique in both the Marcellus and Utica.

“We’ve done a lot of directional air drilling,” Elkin said. “Air drilling is so much more economic—it’s faster, easier and cheaper than fluid drilling. But the technology on directional drilling on air is well behind fluid drilling.”

The technology will be defining in the deep Utica, which has been cost prohibitive. “The more of that hole you can drill on air, the more economic you will be able to make those wells.”

Price pressure cometh

So what effect might Northeast gas have on the U.S. marketplace?

“As soon as the Northeast has outbound capacity, it’s going to be well-connected to the rest of the country,” Johnson noted. “The volumes will move freely, and you won’t see many bottlenecks. That means volumes could end up on the Gulf Coast being sent out for LNG or for industrial purposes. You can bring it from anyplace.”

And considering finding and development costs, Johnson foresees vast volumes that can be produced and transported for a price well below $5/Mcf.

“That means we’re not going to see prices above $5 for any significant periods of time,” she projected.

That’s bad news for unconventional regions elsewhere. “In terms of economics, there’s going to be pressure, because we can more than meet demand at $5.”

Rockies gas will be hit particularly hard, she said, and will need to seek outlets in California and the West Coast, certainly west of the Mississippi. Plays such as the Haynesville and Fayetteville shales are “a little more complicated,” as Tier 1 acreage will remain competitive in the new world order. But, “we don’t expect a large scale return to the Haynesville.”

Mark Rothenberg, CEO of Marcellus operator Apex Energy LLC, predicts a pull on prices as well. “The fact that you have so much production with so much ability to grow that production for a relatively low capital investment is going to put downward pressure on prices overall. If demand doesn’t increase, the Henry Hub price will be pulled closer to the Appalachia price.”

Northeast producers, though, which are sitting on some of the best breakevens in the nation, are going to continue to grow. Many have backed pipelines to assure they can get their gas to markets.

Apex on trend

For now, basin price differentials are the last thing on Rothenberg’s mind. The head of privately held Apex, a 2012 start-up funded by Apollo Global Management, is focused on proof of concept of Marcellus wells in Armstrong and Westmoreland counties, Pennsylvania.

“These initial wells are less about production strategies and more about proving to the investors that everything we said about reserves and well performance is true,” he said. “Our approach now is to tie into the closest pipeline and sell into the pool.”

So far, all of Apex’s production is generated by one well on restricted choke, and sells into the Dominion South hub, realizing about $1.30. “It’s relatively low to Henry Hub, but it’s a highly liquid point and we can move our gas. It’s not a long-term goal, but we’re willing to do that to prove up EURs.”

Even still, the rate of return is near 20%, he said. “Believe it or not, they’re still economic; that was our conviction around the Marcellus.”

Having identified the Marcellus as a career target, Rothenberg moved from Denver in 2009 to join Exco Resources in its Appalachia office. When the Dallas company consolidated that office to its Texas headquarters three years later, with kids in school and not wanting another move, Rothenberg stayed in Pittsburgh and formed Apex with other co-workers.

Along with Apex COO Ed Long, the two engineers focused on reservoir analysis to identify a balance of best rock with the opportunity to build a consolidated position at an affordable buy-in. They built a 45,000-acre portfolio divided between Westmoreland and Armstrong counties, north and east of Pittsburgh.

Why here?

“Everybody knew Washington and Greene counties were good. As we did our trends, we discovered there is an artificial break in activity due to the city of Pittsburgh. It all stopped at Alleghany County, and there is no geologic reason for that to stop.”

The company built positions on the opposite side of Pittsburgh largely ignored due to political boundaries. Rothenberg believes Armstrong County is similar to Range Resources’ wet gas position in Washington County, and its Westmoreland acreage is analogous to the dry gas phase in Greene County.

Even though oil and liquids were en vogue when they were assembling their acreage, gas was the target. “We’re long-term believers in gas,” he said, “but we did like having the mixture of some liquids in case predictions of $200 oil came true.”

Apex’s Armstrong well has been online about a year and continues to wait for additional takeaway capacity to reach its full flow potential, estimated by the end of the year. The company also recently completed two wells in Westmoreland County, expected to be online by year-end as well. Each has cost about $6- to $8 million with 6,000- to 8,000-foot laterals.

The Westmoreland wells are offset by some 100 wells drilled by Consol Energy and Chevron. “We feel there’s very little question about the results in that acreage position with so many existing wells surrounding us and reporting very high reserves levels.”

Rothenberg said internally they’ve proved the concept to themselves, but still need more data to convince anyone external to Apex. But even though they are backed by private equity, the goal is not to find-and-flip the concept.

“For every acreage deal we’ve entered into, we’ve entered into it assuming we’re the last owner. We would love to carry these projects to full development, and are eyeing a finish line years in the future. No one wants to see Apex sold anytime soon.”

And while he doesn’t rule out an exit, an IPO might be the ideal solution down the road to pay out his equity partners.

In the meantime, Apex might defer further drilling for another year or two. “Philosophically, we don’t know if we want to drill right now to get a 20% return when we believe these pipeline projects are going to come on in the next year or two that will hopefully increase local pricing and result in a much higher return.”

Longer term, Apex will implement a firm transport strategy coupled with a marketing or end-user plan. “With all the pipeline projects coming, we don’t expect any issues,” he said.

In fact, he predicts an overbuild by 2017, leaving plenty of available capacity. Much of that will be due to operators that overbought firm capacity and are now jettisoning rigs.

“Clearly, some that bought 20-year contracts at $4 gas and $100 oil aren’t going to be able to fill the firm transport they bought. There are a lot of companies in that situation.”

Driving confidence

With so much pipe coming online, it seems as if the Northeast will be bursting with unlimited supply in a short time. “We could produce a lot more than we’re going to,” said Ponderosa’s Johnson. “The question comes down to demand. We can only grow production as quickly as demand is on the other side to take it.”

Incremental demand additions trail infrastructure expansion until the end of the decade and early 2020s. Until then, “we’re constrained by demand at the other end of the pipe.”

When that demand arrives, she said, then look at the supply stack. “It’s going to be winners and losers; who’s in the best position to grow volumes when that demand shows up? It’s in the Northeast—by far.”

EQT’s Jenkins said the Marcellus-Utica has become what the Gulf Coast used to be as the supply basin for the Northeast, providing long-term conviction of supply for end users such as power plants, fertilizer manufacturers and LNG export facilities.

“It gives confidence to the marketplace that there is certainty around supply to make those large investments,” he said. “It’s economically accessible, with long-term access, for investments that will drive the economy.”

And for the producing community, “it gives confidence that demand is coming and that growth will materialize. There was a point in time when we wondered if the Marcellus would ever be at 20 Bcf/d, and now we’ve crossed that. Now the debate is, will it be 35 [Bcf/d], 40, even 50 a day?”

“If you want to be in natural gas, the Marcellus is the place to be,” said Apex’s Rothenberg. “No other basin offers the potential. Once the infrastructure is put in, you’re sitting on this massive storage field. It’s just a matter of consolidating your acreage and then throttling your activity to be in line with market conditions.”

How much running room is there?

“We’re just now getting our arms around the Marcellus; then there are other formations in the Utica and Upper Devonian that we haven’t touched on what they could mean,” said Johnson. “The Marcellus-Utica is a vast resource that competes with some of the largest fields in the world. It’s here to stay for decades.”

And if EQT and others keep drilling gushers like Scotts Run, the Marcellus-Utica will dominate U.S. natural gas dynamics for just as long.

EQT's Big Utica Well

As EQT Corp. focused diligently on its Marcellus program in southwestern Pennsylvania and West Virginia in 2014, its interest in the dry gas Utica was piqued as the play encroached eastward from Ohio and toward the Pennsylvania state line and its core acreage.

“We knew the Utica had potential,” said David Elkin, EQT senior vice president of drilling and completions. “We also knew it was going to be deep and expensive. Because we had such a good Marcellus position and were having superior results, we weren’t in any huge hurry to test the Utica.”

But the over-pressured regime of the Utica changed rapidly moving east, and that intrigued Elkin, who began modeling the play.

“We were able to determine that, at a certain development cost, the Utica could be as good as or perhaps even better than the Marcellus. We felt it was worth a try to test it.”

But the deep Utica, well below the Marcellus strata EQT was used to drilling, proved to be a different type of well with a steep learning curve.

Initially, the deep intermediate vertical section of the hole at Scotts Run was “very troublesome” to EQT as well as other operators drilling though it. This Salina section of brittle salt and interbedded dolomites has a tendency to slough, causing the bit to get stuck—which it did—resulting in a sidetrack. “That seems to be the graveyard for drilling in the Utica.”

Below that, a section of extremely hard rock chews up bits, slowing down operations and increasing costs.

Only then, when drilling the lateral into the Utica Formation, did EQT find the pressures were even “significantly higher” than anticipated. The rig sitting on hole had a 5,000-pound fluid system, at the edge of being able to contain the maximum pressure. “We were going to be cutting it too close for EQT’s comfort,” Elkin said. A second rig with a 7,500-psi fluid system was brought in.

Though the well design called for a 4,500-foot lateral, the decision was made in motion to hold the lateral at 3,200 feet. First, gas influxes while drilling the lateral indicated “the reservoir was going to be able to contain a lot more gas than what we had initially modeled.

“Just while drilling we knew we had something pretty good. With the gas market constrained, you can drill a longer lateral, but you might not be able to feed that gas, and we didn’t want to have to flare.”

Also, the expense was mounting by the day. “That was a concern,” he said. “We knew it was going to be a prolific reservoir, but because the well was so expensive to drill, we were already questioning how economic it was going to be.”

The shorter lateral mitigated completion costs somewhat, which included more expensive ceramic mixed with sand. Elkin said the Utica’s depth pushes the edge of being able to use natural sand, which crushes in tests under these conditions.

Of course, the ending is already written: a record-breaking 72.9 MMcf/d well on a controlled flow, currently flowing near 30 MMcf/d on choke. Any volume decline—thus reserve estimation—is “several months away.”

Is the Utica a game-changer for EQT?

“For us to make a switch to go to a full-blown Utica program or supplant the Marcellus with Utica, the economics would have to be as good as if not better than the Marcellus. We’re trying to figure out how to drill these wells faster and cheaper. That’s the goal right now.”

EQT is currently drilling a second Utica well in Greene County, Pennsylvania, where the intermediate vertical section “went a lot smoother,” he said. A third well is planned for Wetzel County, West Virginia, by year-end. Both wells’ AFEs are $17 million to $19 million.

“The wells are twice as expensive” as the Marcellus program, Elkin said, “but they may be two or three times as good. If we can make that play economic, we could certainly ramp up growth rates pretty quickly.”

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