Football season swept into Appalachia in September along with ice hockey, while Pittsburgh Pirates fans watched the last few games of the team’s losing season. Cheers for the Steelers (3-1 in early October) and the West Virginia Mountaineers (4-0) filled air space once held by now-shuddering cold-stacked rigs.

The school and some of the rigs are Henry Harmon’s. His alma mater is situated on the eastern edge of the Marcellus-Upper Devoni¬an-Utica trifecta where combined gas in place is estimated to be more than 300 billion cubic feet (Bcf) per square mile. He laid his last rig down at the end of 2014. About half of his gas was shut in this fall.

“We’ve been down for well over a year and a half,” said Harmon, president and CEO of pri¬vately held, Charleston, West Virginia-based Triana Energy LLC. “We decided to conserve cash and wait and see what happened. We’ve just been watching it continue to slide.

“Last week, gas was going into the Domin¬ion system for 88 cents an Mcf [thousand cubic feet]. You’re not making any money on that.”

Fill season

But something was afoot. Besides the E&P business, Harmon also operates active rigs. One of his rigs was picked up in late Sep¬tember and another one was heading out in October.

The basin’s count had declined to a low of 21 in early August, according to the weekly Baker Hughes Inc. count, from 140 in early 2012. Shortly thereafter, the Nymex price fell below $2 and has rarely found $4 ever since. This past winter, it was as low as $1.66.

But the regional rig count improved in the early days of this autumn to 32, the Nymex price started with a “3” and the gas-storage-fill season had been curious. During the 2015 fill, producers had deposited nearly 2.1 trillion cubic feet (Tcf) by September-end, accord¬ing to data from the U.S. Energy Information Administration (EIA).

This year, 1.1 Tcf was added by then. In July, there was a net draw. Simmons & Co. Interna¬tional Inc. lead analyst Pearce Hammond noted that this had happened during the summer only twice before—both in 2006.

It’s the result of myriad new gas dynamics. The U.S. gas-directed rig count began 2016 at 148 versus 340 at year-end 2014, according to Baker Hughes. More than 3.5 Bcf a day was going to Mexico compared with about 1.5 Bcf/d in January of 2015, according to research firm PointLogic Energy. LNG exports commenced earlier this year.

And the oil-directed rig count that was nearly 1,500 in January of 2015 had tumbled to as few as 316 this past May. Associated-gas produc¬tion this past spring was 10% less than a year earlier, according to Jefferies LLC.

The increased demand and reduced supply were adding up. U.S. gas in storage exiting this past winter had been 67% greater than a year earlier; East Coast, 53% more; South-Central region, 99% or nearly twice as much. By the end of September, however, the year-over-year figure had declined to 2.1%; in the East, to 5%; in South-Central, 2.6% less than the year before.

Jeff Ventura, chairman, president and CEO of Range Resources Corp., told Oil and Gas Investor, “2016 will be the first year U.S. natu¬ral gas production declined on a year-over-year basis since 2005. That will carry into 2017 as well. As demand is going up, supply is going down. We think the gas market is going to be much better balanced going forward.”

Market optionality

Ventura visited with Investor the morn¬ing Range closed its merger with Memorial Resource Development Corp. In that, it added 220,000 net Lower Cotton Valley acres in north¬western Louisiana to its 1.5 million acres of Marcellus, Utica and Upper Devonian.

If the Marcellus is the North American gas tiger, why buy anything else? “The Memorial production and acreage is ideally located on the Gulf Coast,” Ventura said. “They get near-Ny¬mex pricing. It’s high-quality rock. The returns, we think, are very comparable to the Marcellus.”

Memorial’s Terryville Field has been excep¬tional. But Seaport Global Securities LLC ana¬lysts report that the acreage Range has picked up south of Terryville and toward Vernon Field, representing some 80% of the leasehold, may make wells that are even better.

And the gas is in a prime zip code. Ven¬tura said, “Having core, high-quality, large acreage positions in what we think are the two best gas plays in the U.S. makes us a pre¬mier gas company and it also gives us a lot of optionality.” For example, during normal U.S. Northeast winters, “we can leave our gas ‘in basin,’” selling it at a higher price there, “and supply our Gulf Coast contracts with Terryville gas.”

Currently, Range is sending nearly 300 million cubic feet per day (MMcf/d) of its Marcellus gas to the Gulf Coast; next year, that is expected to grow to 510 million a day. It doesn’t sell anything priced at the New York City Gate, which was paying 64 cents a million Btu at September-end. “By the end of this year, 80% of our gas will be going to favorable markets. By the end of next year, that will be 90%,” Ventura said.

Ventura sees 16 Bcf of incremental gas demand by 2020 and another 15 Bcf by 2025. The U.S. base decline is 7 to 9 Bcf a year. Demand growth is primarily along the Gulf Coast, driven by LNG exporters, Mexico, and power-gen and petchem-plant operators.

U.S. demand during the aughts averaged 62 Bcf/d, according to EIA archives; in the past six years, it has averaged 70 Bcf/d. In 2015, demand was 75 Bcf/d with an extraordinarily cold winter followed by an extraordinarily mild autumn.

“Winter, winter, winter,” John Walker, CEO of private operator EnerVest Ltd., said of the season’s leading role in gas prices at Hart Energy’s annual A&D Strategies conference recently. A record hot summer day does con¬tribute an uptick in demand by about 40 Bcf, he said. “But, in the winter, we’ve had days of more than 200 Bcf.”

Walker bought Range’s prized Nora Field in Virginia for $865 million at year-end 2015. Although Ventura liked the people and assets, letting it go was the right decision from a purely business point of view, he said. “Our strategy has been simple: We’re a commodities business. We want to be in the highest-quality, lowest-cost plays with repeatability.”

Range bought the first half of Nora in 2004. Its horizontal Marcellus program began in 2007. “Nora didn’t compete with the Marcel¬lus,” Ventura said. “We found a buyer at an attractive price.”

Meanwhile, Memorial’s northwestern Lou¬isiana assets do compete with the Marcellus. “It makes us a better, stronger company.”

Balance sheet

The Fayetteville play’s founder, Southwest¬ern Energy Co., has added outside its core portfolio too—in this case, in the Marcellus. Jack Bergeron, senior vice president, E&P operations, said, “Everything we do is chase high-quality rock. The Marcellus is the best rock in the shales, the most prolific. We were just chasing good rock.”

Southwestern has had nearly 1 million net Fayetteville acres for more than a decade now. It started leasing in the Marcellus in 2007 and added some from Chesapeake Energy Corp. in 2013 in the northeastern part of the Marcel-lus fairway. Its first 115,000 net acres cost an average of $530 an acre. “We started drilling wells and they performed much better than we thought they would,” Bergeron said.

In late 2014 and early 2015, it went in for more in an expansion into the southwestern Marcellus in southwestern Pennsylvania and north-central West Virginia. The $5 billion deal with Chesapeake was financed with a $4.5 billion 364-day bridge loan and an additional $500 million two-year loan, both unsecured. It purchased additional assets from Statoil ASA in the southwestern Marcellus and added in the northeast from WPX Energy Inc. for a combined $627 million.

At the time, equity and debt markets were still reeling from a plummeting oil price. Whether Southwestern would work out its balance sheet into 2016 as gas prices were plummeting too looked like a nail-biter.

But “we had no problem,” Bergeron said. “We had a plan to manage that debt and a great relationship with our banking group. That, plus high-quality assets and maturities pushed a little bit further, and we reduced our debt with equity again this summer as well as with some targeted asset sales.”

It initially raised a net $2.3 billion in com¬mon- and preferred-share sales to pay down the loans. It raised an additional net $1.25 bil¬lion in an equity offering this summer, paid down bank debt by $375 million and paid down notes due in 2018 by $700 million. It sold some of its West Virginia leasehold for $450 million to Antero Resources Corp.; gathering assets in northeastern Pennsylvania for $500 million; and East Texas and Arkoma Basin assets for $218 million.

The southwestern Marcellus expansion is a contiguous acreage position. “We thought, with the scale we demonstrated in the Fayette¬ville, we could bring the cost down and bring the production up by innovation in comple¬tions and landing our wells,” Bergeron said. “And we were right.”

Length, proppant, landing

By early 2016, it had 270,000 net northeast¬ern Marcellus acres—about 38% HBP by 424 horizontals. In the southwest, it had 425,000 net acres—about 54% HBP by 318 horizon¬tals and 676 legacy verticals. Southwestern has four rigs drilling for it in Appalachia—two northeast; two, southwest.

In the northeast, it’s taken proppant per lat¬eral foot from 1,300 pounds to testing more than 2,000. “We now consider low to be 2,000 pounds per foot,” Bergeron said.

In the southwest, its focus is on tighter stage spacing—down to 100 feet—due to the wet nature of the gas versus the dry nature northeast. “So we have tighter stage spacing in the southwest and we’re trying it in areas of the northeast as well. We’re trying to push the envelope.”

It has drilled 12,000-footers “and we haven’t seen any degradation,” he added. Its average lateral length in the southwest is 7,500 feet; in the northeast, 5,500 feet. From the longer tests, “we actually see a little flatter decline,” he said.

It’s also producing its wet-gas wells on more choke. “It’s one of the reasons we believe we are outperforming the previous operator there.”

Landing in the northeast is mainly in the lower portion of the Marcellus. “We drilled some in the upper Marcellus with mixed results. Again, that’s economics.”

The Marcellus thins trending southwest, but it’s better rock, he said. “I wouldn’t call it upper or lower there. It’s just the Marcellus there. We tend to keep it in about a 15-foot interval we feel is the sweet spot that we are technically able to keep it in and get the best wells performance-wise.”

Lower oilfield-service costs are “the perfect environment right now,” he added, “to do some learning. We have thousands of wells left to drill in the Appalachian Basin, and we’re tak¬ing this opportunity to learn what we can. We know we can make better wells, but we’ve got to get the return on investment.”

From its southwestern expansion, it inher¬ited one Utica well. It was completing one of its own—an 8,000-footer—at press time and expected to release the data in its fourth- or first-quarter results.

Southwestern used its Marcellus completion recipe for that well. “Being dry gas and our first Utica well, we’re trying to be consistent with the others. I would expect technology will lead us to more sand and longer laterals in the Utica as well.”

Utica, Upper Devonian

In the northeast, Southwestern hasn’t tested the Utica, but neighbors’ wells in Tioga County are on trend with its acreage. “We have excel¬lent economics in the Marcellus and we believe the Utica is going to become more competitive as time goes on.”

It also has Upper Devonian potential in the southwest. “We haven’t drilled it yet, but we feel it is highly prospective.”

Range has drilled Utica and Upper Devonian wells, but it continues to target the Marcellus primarily. Ventura said, “That’s where we believe we have the best returns and we have thousands of locations to drill.”

What’s the latest greatest? “We’re still learn¬ing,” Ventura said. “Our average wells this year are on the order of 7,000 feet and we continue to march out with longer laterals. I don’t think we’ve found an optimum yet, but it continues to be longer.”

Range’s pads were constructed for up to 20 wells each, but the company delayed filling them out while HBPing its leasehold. Today, it has very little acreage at risk of expiration and what is will be held.

“We have the ability to go back to the pads,” he said. “They typically have five to 10 wells and a lot have fewer. The potential to go back to those pads will help with capital efficiency.”

SGS analysts estimate Range has more than 230 pads in the Marcellus that could take 20 wells each. Each additional well could cost $700,000 less than a well on a new pad, they added. In the dry-gas area, a five-well pad could EUR an average of more than 3 Bcf per 1,000 feet of lateral. According to Range, the wells cost $5.2 million each.

While Range is doing well, one operator’s success in the basin doesn’t necessarily reflect the potential of all operators in the basin. Ven¬tura said, “That’s an important point. People tend to generalize. Where you are in the play makes a difference. The rock varies. You can see it in the gas-in-place maps. It varies.

“Even in the southwestern part of the play, the hydrocarbon varies significantly. It’s not all equal. The best thing to look at is performance over time.”

Last man standing

Henry Harmon is glad to be a private opera¬tor and with very little debt in this persistently poor gas-price environment. He wasn’t in a rush to start drilling again.

The company held 150,000 acres in 2013, including land Marathon Oil Corp. con¬veyed to it upon exiting the basin. With sales and expirations, Triana’s leasehold today is about 40,000 net acres, all in West Virginia and including a little bit of the Marathon leasehold.

Some 30,000 acres are contiguous, and Triana estimates it holds a Tcf of dry gas in place. Tri¬ana’s reserves are between 1.8 and 2 Bcf, all dry gas, per 1,000 lateral feet.

It’s put 11 wells in the Marcellus from three pads. “We believe we can drill at least another 120 wells with laterals between 5,000 and 8,000 feet from 23 pads on the property,” Harmon said.

“We would populate our pads with between four and eight wells, depending on surface cul¬ture and lease boundaries. We hesitate to crowd a pad with more than eight wells, but our design is usually determined by the circumstances.”

West Virginia had been the home of coal, but a low gas price continues to push it out of the market. In the state, Harmon said, “promoting coal is still a priority of politicians, but I believe that the workforce and infrastructure have been damaged to an irreversible point. It is no lon¬ger viewed as a competition between the two extraction industries.

“The regulatory environment is very profes¬sional and, in many ways, less burdensome than in some of the surrounding states. Everyone rec¬ognizes that we need to maximize the potential of both [coal and gas] to create the best outcome for this nation.”

He expects some operators will sell legacy acreage beginning in 2017. “Who is the last man standing hasn’t been determined yet. A number of companies are trying to figure out if they can stand any longer. I’m not sure who’s going to buy all of this. There are literally tens of thou¬sands of wells.

“People need to sell to generate cash. We’ve seen a few failed offerings in the past year to 18 months—even in the wet Marcellus—where there are problems with pipeline commitments and the cost of processing those liquids is more than it’s worth.”

Triana took on relatively little debt in its hunt; its equity partner is Morgan Stanley Energy Partners, chaired by John Moon, who led investment in Triana I, which was sold to Chesapeake for $2.2 billion in 2005. “We didn’t grow [Triana II] as dramatically as some of the other private guys, but we don’t have the debt load,” Harmon said.

Access to capital will determine who survives. “The big guys are still playing their arbitrage game. They’re losing hundreds of millions of dollars each quarter, but they report record pro¬duction. They’re producing oversupply into a low price. People just keep producing.”

DUCs

The EIA began to report on drilled-but-un¬completed wells (DUCs) in September, based on data it began collecting in 2014. Its estimate for the Marcellus for August was 642.

Bernstein Research analysts have their own count: 1,241. Senior analyst Jean Ann Salisbury wrote that it is derived by splitting the difference between numbers produced by the EIA’s meth¬odology versus that of Rystad Energy, which estimates nearly 1,500 DUCs in the play.

Harmon said the number is declining. “We’re seeing more wells connected than they’re drill¬ing, so you know they’re going through their backlog of DUCs. That’s encouraging.”

More wells will be added to inventory too, he expected. His drilling company, Highlands Drilling LLC, has customers talking about add¬ing iron in December and January.

The company is ISO 14001 certified with an incident rating of almost zero, so the crews he let go were quickly hired in and outside of the field. In addition to the rigs he was already crewing up at press time, “we’d have to do some recruiting to get more back out,” he said.

Meanwhile, what keeps Harmon busy these days, without a drilling program and half of his production shut in? “Not to say we won’t reig¬nite our development program next year, but we’re not in a hurry to make a wrong decision.”

Southwestern is keeping discipline as well. Bergeron said, “We’re not going to grow just for production’s sake. We want to create value.”

Southwestern is advantaged by having affordable take-away contracts, he added. “We have been able to move gas at a reasonable cost to higher-value markets, and that’s one of the reasons we have strength in the basin.”

Harmon agreed on takeaway: “If we can get the gas to the market, this is the place you want to be if you’re a gas producer.”

Pipe slowdown

Bernstein’s Salisbury made note of take-away constraints as well in her September report on the region. “Even if the rigs show up, there needs to be pipeline capacity to move the produced gas to market,” she wrote. “This will come, but not until the end of 2017.”

R.W. Baird & Co. Inc. analysts published an epistle in September on valuing pipeline oper¬ators going forward to factor for the potential for delays and denials. “Everywhere you look, federal agencies are slowing down pipeline con¬struction,” they wrote.

Among them is PennEast, just 119 miles long in Pennsylvania and New Jersey, Baird reported. A FERC report that was due Sept. 2 on converting part of Tennessee Gas to NGL has been postponed until after the January inauguration. A city in Ohio wants a new route for another pipeline.

In addition, the Atlantic Coast and Moun¬tain Valley lines that are to take Marcellus gas southeast drew a third-party white-paper con¬clusion that existing infrastructure is sufficient.

Harmon said the U.S. gas supply/demand market may have found equilibrium for now, but increased access to demand centers is essen¬tial, particularly in the U.S. Southeast. “The Tidewater areas of Virginia and new markets in the Carolinas, Georgia and Florida are where the opportunity is for Appalachian producers. The Atlantic Coast and Mountain Valley pipe¬line projects are critical to get this gas to mean¬ingful markets.”

The negative Appalachian differential will nar¬row, “but maybe not until 2019 when all of these new markets are engaged.”

As a gas producer, he said, the messaging from Washington is confusing. “The whole impetus was to get the coal-fired [power-generation] plants converted to gas to have the carbon savings, and it’s worked. We’re meeting those arbitrary targets, and now we’re not being allowed to get the gas to those new markets.”

He believes election results on Nov. 8 will give producers an idea of what to expect in the next four years: “It will get better or worse. It won’t be the same.”

Range is shipping its ethane to Sarnia, Ontario; to the Pennsylvania coast for export via sea; and to the Houston Ship Channel via the Appalachia to Texas pipeline. Its propane is shipped to the coast as well for export or, when local demand is greater, for local use.

Southwestern has capacity on Atex to the Texas coast as well, Bergeron said. It also has contracted capacity on Mariner West to Sarnia. It doesn’t have a commitment on Mariner East to the Pennsylvania coast, but it is able to sell into it. “On the liquids side, it never hurts to get more access to the export market,” Bergeron said.

SGS analysts reported recently that chemical demand is pegged to grow some 1% above GDP between now and 2040, and demand for ethylene is expected to grow 4% annually. “This translates into about 6 million to 7 million tons per annum of additional capacity, which is approximately four to five world-scale crackers added per year,” they wrote.

Gas futures

The mid-September add to storage was 49 Bcf, which was less than expected. Tudor, Pickering, Holt & Co. analysts estimated that, on a weather-adjusted basis, demand was undersupplied by 4.5 Bcf/d, “significantly tighter than the 3 Bcf/d average undersupply we have been seeing.”

Canada has approved the Pacific Northwest LNG terminal at British Columbia, which should send some excess supply potential offshore rather than into the U.S. The clear¬ance requires project developers meet 190 conditions, including a greenhouse-gas-emissions cap.

Bernstein’s Salisbury wrote that, while the Nymex price has improved to $3, “in the long run, we are cautious on gas, which we believe should be range-bound at $3 an Mcf.”

It’s that tiger effect. The region’s produc¬tion is some 18 Bcf/d currently, according to the EIA. The northeastern portion, which has been choked at about 8 Bcf/d due to take-away constraints, will grow to more than 10 Bcf/d through 2020, she reported. Meanwhile, other basins need more than $3 an Mcf.

She also estimated that the current Marcel¬lus-region rig count needs to double just to keep total output flat, “so production will fall in 2017. We therefore believe that 2017 may offer a short-lived window of opportunity for gas investors.”

Gas may spike to above $4. “We expect that the rig count will surge mid-2017 as operators prepare to fill new pipelines. This will put the lid back on the gas price and ensure the rally comes to an end. But, if we don’t see a sig-nificant rise in rig count [before summer], the price rise may be more sustained.”

Her expectation is for an average of $3.50 an Mcf in 2017, returning to $3 as supply grows. Research firm Ponderosa Advisors LLC proj¬ects $4.50 gas in 2017, declining to $4.15 in 2018, $4 in 2019 and $3.75 in 2020.

Managing for sub-$4

At a higher gas price, what would Range do? Ventura said the greater cash flow would allow accelerated development to pull returns forward for shareholders. It would continue to work on capital efficiency as well as continue to experiment with longer laterals.

With the warm El Nino weather cycle’s end, he expects a normal winter this year, thus increasing gas demand and giving uplift to prices. Meanwhile, producer cash flow and out¬spending are down. “So supply/demand funda-mentals are much better as you look forward.”

For 2017, more than 40% of Range’s gas is hedged at $3.20 a million Btu, including pro¬duction it gained from Memorial. Gas futures may spike above $4 at times, “but our invest¬ment plans are based around sub-$4 gas for the mid-term,” Ventura said.

“That’s why we tried to build such a high-quality inventory. Prices sustained above $4 make other basins start to become economic and that will keep prices below or around $4. Focusing on low-cost, high-quality assets—with a high-quality, creative marketing team—results in better margins, regardless of the price cycle.”

Triana’s Harmon agreed: “I'm not very opti¬mistic about sustaining a Henry Hub pricing of $4 because there is just such a glut of LNG on the global market. We will have to see U.S. LNG sustaining a major position in Asian and European markets before we can say there is any real support for prices at that level.”

Overall, he added, “The current downturn has hurt the industry in a way that will be felt for a generation.” Young people who entered the busi¬ness in this century have been laid off and many are not coming back. Meanwhile, the generation that started out before the 1980s bust is retiring.

“I see a lot of consolidation happening in the next two years, and the industry is likely to look much different when it is finished.”