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Despite price bounce, natural gas rebound remains far off

| Saturday, May 28, 2016, 9:00 p.m.
A worker tends to a drill pad near  Majorsville in West Virginia.
Andrew Russell | Tribune-Review
A worker tends to a drill pad near Majorsville in West Virginia.

The benchmark price of natural gas recently spent an entire month above the $2 mark, buoyed by optimism that shale drillers were dialing back on record production and prompting speculation that a nearly two-year downturn for the industry was rounding a corner.

The reality of an unbalanced market returned last week.

“Just when you thought it was safe to write about recovery, we see a price relapse,” said Teri Viswanath, managing director for natural gas at New York-based analyst Pira Energy Group. Natural gas futures back below $2 per million British thermal units “suggests the market might be having second thoughts about the industry's ability to cope with surplus supplies this season,” she said.

The rebound from a March 3 price of $1.64 — a 17-year low — boosted shares at companies that have been battered by deep losses and spurred talk of ramping up rates of drilling that fell to levels not seen since the shale boom began more than a decade ago. The New York Stock Exchange's Arca natural gas index has increased 54 percent from a 52-week low in January.

But analysts and executives warn that a sustained price rebound capable of supporting a normal level of drilling and employment is at least a year or two away, and will require production cuts until demand increases in the form of exports and more use by the power sector and more pipelines are built.

“We think that the market's going to remain stressed given this current supply situation ... into 2017,” Consol Energy CEO Nick DeIuliis told analysts during a recent earnings call.

The Cecil-based producer laid off staff and stopped drilling new wells last year as it works through an inventory of previously drilled wells. Although its stock tripled to $15 from a 52-week low in January and executives see signs of better gas prices in the next two years, they said it's too early to predict when a return to drilling will occur.

The slowdown in drilling only dented production so far, partly because companies continue to get more gas from new wells through better techniques and they are bringing online previously drilled wells. Pennsylvania production of 1.28 trillion cubic feet in the first quarter outpaced the same period last year by 12.7 percent and the last quarter of 2015 by 7.3 percent. Nationwide numbers fell by nearly a billion cubic feet per day in March and April, but are flat for May.

Observers worry that any increase in drilling could boost supply before demand increases, pushing prices down further.

Underscoring those concerns, drillers have not increased capital budgets that they slashed over the past three years.

“With structural demand only beginning to materialize, sustainable price recovery ultimately hinges on supply-side balancing,” Viswanath said. “The trouble is, despite the plunge in capital spending, production declines, while already visible, are not occurring fast enough to curb the build in inventories.”

In parts of Pennsylvania's Marcellus shale, a true rebound could take even longer as pipelines aimed at taking gas to more lucrative markets face longer delays and more opposition. The Federal Energy Regulatory Commission lists 18 pending pipeline construction or expansion projects in Pennsylvania.

“I believe confidence in Henry Hub is coming back,” Subash Chandra, a New York-based analyst at Guggenheim Securities, said regarding the improved national prices. “Companies have to figure out what it means for them. But if I'm in the Northeast, it may not mean much.”

As low as the benchmark prices have gone — as measured at the Henry Hub trading point in Louisiana for spot prices and the New York Mercantile Exchange for futures contracts — producers here are getting 55 cents less per million Btus. There's nowhere to put all the gas.

“Northeast Pennsylvania is going to have more trouble. Talk about opposition against every project,” said Matthew Hoza, a senior energy analyst in Colorado at BTU Analytics. New York environmental regulators recently blocked the Constitution Pipeline set to deliver gas to that state and Kinder Morgan canceled its Northeast Direct project into New England, where high demand from power plants and home heating brings increased prices.

“If more projects get cancelled that would give relief to Northeast Pennsylvania, we're looking at it being even longer,” Hoza said.

Producers looking for ways out of the stranded Appalachian basin might have a new model.

Fort Worth-based Range Resources was the first to tap the Marcellus in 2004 and recently has directed nearly all its spending and well development in this region. But it has pushed to sell its gas and liquids outside the area, including exports of ethane and propane to Europe that began this spring. Last month, CEO Jeff Ventura told analysts that 70 percent of its gas would sell outside Appalachia this year, and 82 percent by the end of 2017. Finding new markets here and abroad can help ease the glut.

This month it announced a merger with Houston-based Memorial Resource Development that will give Range wells and land to drill in Louisiana, closer to the more lucrative Henry Hub pricing point, export terminals and new pipelines to Mexico. Ventura cited that area's “close proximity to growing demand and the higher prices near the Gulf Coast” as benefits of the merger.

Experts have expected more companies to respond to the downturn with mergers and acquisitions. Hoza said deals like Range's that involve broadening their markets could become a trend.

“It's definitely an option that has to be on the table,” Hoza said. “It's a diversification away from pure-play Marcellus.”

Ventura insisted, though, that Range has no plans to abandon its Appalachian position. “We think differentials in the Marcellus will improve with time, particularly in the southwest part of the play,” he told investors.

In quarterly earnings calls over the past month, executives explained why they see potential for a price rebound over the next year or two. Even with previously drilled wells to frack and improved performance from each well, most expect the drop in drilling rigs to eventually have an effect on production.

“Appalachia is currently producing around 22 (billion cubic feet) per day, and there are 35 rigs active in the basin. However, our analysis of historical state data tells us that the basin needs 50 rigs to 55 rigs to maintain flat production,” Daniel Rice IV, CEO of Cecil-based Rice Energy, told analysts this month.

The effect of less drilling usually takes at least a year to show up in lower production. “We think this lack of growth from the basin sets the stage for an improving gas market in 2017 and 2018,” Rice said.

The slowdown in oil drilling that began a few months before gas prices started falling has led to less so-called associated gas coming from Midwest oil wells. If that keeps falling and Appalachian producers follow, supply levels could begin to drop, especially if a hot summer drives up demand from power plants.

The legacy of a mild winter threatens to slow the rebalancing, though.

With less demand from utilities, especially during the warmest December in more than 100 years, gas storage ended the winter heating season at a record high: about 2.5 trillion cubic feet. The year before that figure was 40 percent lower. Further injections into those reserves — which usually provide a relief valve for summer production — “are expected to be limited by available storage capacity,” the Energy Information Administration said last month.

Again, producer have slowed how much gas they're adding to storage, but not enough.

“Because the current pace of restocking places the industry on a collision course with physical storage limits, something has to give,” Viswanath said. “Moreover, in the absence of an even more discernible expansion of production losses, that something appears to be price based on the market's recent sell-off.”

Without a drastic cut in production, producers will have to await pipelines to get more gas out of Appalachia and into Mexico and the Southeast, and more export terminals to send it overseas.

Analysts predict that won't happen until at least 2018.

David Conti is the assistant business editor at the Tribune-Review. Reach him at 412-388-5802 or

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